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DRAFT OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY
AIR QUALITY DIVISION
MEMORANDUM January 15, 2018
TO: Phillip Fielder, P.E., Permits and Engineering Group Manager
THROUGH: Rick Groshong, Environmental Manager, Compliance and Enforcement
THROUGH: Phil Martin, P.E., Manager, Existing Source Permits Section
THROUGH: Amalia Talty, P.E., Existing Source Permits Section
FROM: David Schutz, P.E., New Source Permit Section
SUBJECT: Evaluation of Permit Application No. 2017-1011-TVR
Targa Pipeline Mid-Continent LLC
Coalgate, Tupelo and Stonewall Gas Plants (FAC ID 6265)
Section 6, Township 1S, Range 10E
Coal County, Oklahoma
Driving Directions: From Coalgate, Northwest on US-75 4.75 Miles, South to
Plant Site
Latitude: 34.58579o, Longitude -96.29188o
SECTION I. INTRODUCTION
Targa Pipeline Mid-Continent LLC (Targa) has requested a renewed Part 70 operating permit for
the Coalgate/Tupelo/Stonewall Gas Plants (SIC 1321). The facility is currently operating under
Permit No. 2006-309-TV (M-9) issued December 4, 2017.
No changes were requested from the previous operating permit.
Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) in the following
outline. Except for the emergency engines, natural gas is the primary fuel with the non-
emergency engines being operated continuously.
SECTION II. PROCESS DESCRIPTION
The Coalgate plant has been designed for a processing capacity of up to 85 MMSCFD field gas,
while the Tupelo plant is designed to process 145 MMSCFD field gas. Both liquids extraction
plants are subject to NSPS, Subpart KKK. The Stonewall gas processing plant is designed to
process 205 MMSCFD of field gas and is subject to NSPS, Subpart OOOO.
PERMIT MEMORANDUM 2017-1011-TVR 2 DRAFT
There are 2 different pressure gas streams entering the gas plants. Mid-pressure inlet gas enters
the plant from 50-90°F at approximately 650 psig. The gas is routed through an inlet gas
separator. Some gas then proceeds to the booster compressors (TC-1 and TC-2) where the
pressure is raised from approximately 650 psig to 900 psig in one compression stage, and is then
routed only to the Tupelo Gas Plant. Other mid-pressure gas proceeds directly to the Coalgate
Gas Plant. High pressure (~900 psig) inlet gas enters directly into the Tupelo and Stonewall Gas
Plants at 50-90°F, after passing through inlet separation equipment.
The gas will then flow to each plant’s respective amine units. The inlet gas contains CO2 but
almost no H2S, so the amine unit is designed to remove the CO2. The rich amine is regenerated
with heat from hot oil heaters (CH-1, H-701, SA-1, and SA-2) so that the lean amine can be re-
circulated back to the amine contactors. All amine unit still vents (CAV-1, TAV-1, SAV-1 and
SAV-2) will be routed to a thermal oxidizer or treatment system using SulfaTreat or a liquid H2S
scavenger, or equivalent, to control any H2S in the vent to >95% efficiency. The treated gas is
routed from the amine units through TEG dehydration units where any entrained water is
removed. The rich TEG is sent to the reboilers (CRB-1, TRB-1, SRB-1, and SRB-2) where it is
regenerated so that the lean TEG can be returned to the process. BTEX eliminators control the
potential benzene, toluene, ethylbenzene and xylene (BTEX) emissions from the reboiler still
vents (CSV-1, TSV-1, SSV-1, and SSV-2). The BTEX eliminators condense the still vent gas
stream and route the non-condensable vapors back to the dehy’s firebox, which utilizes a
continuous ignition system.
The dried gas from the TEG contactor goes to the cryogenic skid where it passes through a mole
sieve bed to remove the remainder of the water, and then through a series of heat exchangers,
including propane refrigeration, therefore pre-cooling the gas in order to create higher plant
efficiencies. The pre-cooled gas is then expanded to approximately 180-300 psig through a
turbo-expander to further chill the gas. Residue gas at this point passes through heat exchangers
for energy recovery, is compressed by the turbine side of the turbo-expander, and is then
compressed by residue gas compressors (C-1 to C-7, TC-4 through TC-8, and SC-1 through SC-
6) to pipeline delivery pressure (~ 950-1200 psig).
Free-liquids collected in inlet separators are sent to intermediate flash separators, which operate
between 120-200 psig. Then Coalgate and Tupelo Plant’s free liquids are routed to a stabilizer,
and after stabilization they are sent to the atmospheric condensate/water storage tanks (TK-801
through TK-810). Flash emissions, breathing and working losses from the condensate storage
tanks, and flash vapors from the intermediate flash separators are currently controlled by a vapor
recovery system. The vapor recovery units (VRU-1 through VRU-4) operate as a closed-looped
system and have no associated emissions.
The Y-grade liquids recovered from the cryogenic process go to the NGL pipeline.
PERMIT MEMORANDUM 2017-1011-TVR 3 DRAFT
SECTION III. EQUIPMENT
Sources of emissions are listed in the following table. The facility may also contain ancillary
equipment such as lube oil, ethylene glycol, and TEG storage tanks that are not subject to any
emissions limitations or requirements and are not addressed any further.
EUG-COMP1: Stationary Engines Not Subject to NSPS Subpart JJJJ
EU Emission Unit Description Manufacture
Date
Serial
Number
C-1 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2007 C-16938/1
C-2 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2007 C-16939/1
C-3 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2006 C-17207/1
C-4 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2006 C-17209/1
C-5 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2007 C-16941/1
C-6 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2006 C-17208/1
C-7 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2007 C-16940/1
C-8 1,478-hp Waukesha L7042GSI with Catalytic
Converter 2007 C-14136/1
EUG-COMP2: Stationary Engines Subject to NSPS Subpart JJJJ
EU Emission Unit Description Manufacture
Date
Serial
Number
SC-1 2,370-hp Caterpillar G3608LE with oxidation
catalyst May 2013 BEN00843
SC-2 2,370-hp Caterpillar G3608LE with oxidation
catalyst May 2013 BEN00844
SC-3 2,370-hp Caterpillar G3608LE with oxidation
catalyst May 2013 BEN00847
SC-4 2,370-hp Caterpillar G3608LE with oxidation
catalyst May 2013 BEN00848
SC-6 2,370-hp Caterpillar G3608LE with oxidation
catalyst January 2015 BEN01101
TC-1 1,380-hp Caterpillar G3516B with oxidation
catalyst May 2011 JEF01180
TC-2 1,380-hp Caterpillar G3516B with oxidation
catalyst May 2011 JEF01179
PERMIT MEMORANDUM 2017-1011-TVR 4 DRAFT
EU Emission Unit Description Manufacture
Date
Serial
Number
TC-4 1,775-hp Caterpillar G3606 LE with
oxidation catalyst April 2011 4ZS01530
TC-5 1,775-hp Caterpillar G3606 LE with
oxidation catalyst October 2011 4ZS01586
TC-6 1,775-hp Caterpillar G3606 LE with
oxidation catalyst
September
2008 4ZS01047
TC-7 1,775-hp Caterpillar G3606 LE with
oxidation catalyst August 2010 4ZS01425
TC-8 1,775-hp Caterpillar G3606 LE with
oxidation catalyst
February
2011 4ZS01515
S-GEN3 27-hp Generac 58130 Generator 2014 8421250
10096
EUG-EMRGEN: Stationary Engines Subject to NSPS Subpart IIII
EU Emission Unit Description Construction
Date
Manufacture
Date
Serial
Number
C-GEN
(Coalgate)
1,881-hp Kohler 1250REOZMB
diesel engine 2012 July 2008 16260
T-GEN
(Tupelo)
2,346-hp Kohler 1600REOZMB
diesel engine 2012 Feb 2011 17252
S-GEN1
(Stonewall)
2,923-hp Kohler 1750REOZMB
diesel engine 2013 June 2013 19393
S-GEN2
(Stonewall)
2,923-hp Kohler 1750REOZMB
diesel engine 2013 June 2013 19420
EUG-DEHY: Glycol Dehydration Units
EU Emission Unit Description Construction
Date
CSV-1 Dehydration Unit Still Vent / BTEX Eliminator (Coalgate Plant) 2007
TSV-1 Dehydration Unit Still Vent / BTEX Eliminator (Tupelo Plant) 2011
SSV-1 Dehydration Unit Still Vent / BTEX Eliminator (Stonewall Plant) 2014
SSV-2 Dehydration Unit Still Vent / BTEX Eliminator (Stonewall Plant) 2014
EUG-HOH: Hot Oil Heaters
EU Emission Unit Description Construction Date
CH-1 20-MMBTUH Heater (Coalgate Plant) 2007
H-771 19.45-MMBTUH Heater (Tupelo Plant) 2011
H-701 12.15-MMBTUH Amine Heater (Tupelo Plant) 2011
SA-1 12.15-MMBTUH Amine Heater (Stonewall Plant) 2014
SA-2 10.08-MMBTUH Amine Heater (Stonewall Plant) 2015
H-781 17.42-MMBTUH Hot Oil Heater (Stonewall Plant) 2014
PERMIT MEMORANDUM 2017-1011-TVR 5 DRAFT
EUG-INSIG HTR: Insignificant Heaters
EU Emission Unit Description Construction
Date
H-700 5.5-MMBTUH - Heater (Tupelo Plant) 2011
CRB-1 2-MMBTUH Dehydrator Reboiler (Coalgate Plant) 2007
TRB-1 2-MMBTUH Dehydrator Reboiler (Tupelo Plant) 2011
H-741 5.61-MMBTUH Mol Sieve Heater (Stonewall Plant) 2014
SRB-1 1.5-MMBTUH Dehydrator Reboiler (Stonewall Plant) 2014
SRB-2 1.5-MMBTUH Dehydrator Reboiler (Stonewall Plant) 2015
EUG-TANK: Condensate Tanks
EU Emission Unit Description Construction Date
T-801 400-bbl Condensate Storage Tank 2007
T-802 400-bbl Condensate Storage Tank 2007
T-803 400-bbl Condensate Storage Tank 2007
T-804 400-bbl Condensate Storage Tank 2007
T-805 400-bbl Condensate Storage Tank 2011
T-806 400-bbl Condensate Storage Tank 2011
T-807 400-bbl Condensate Storage Tank 2011
T-808 400-bbl Produced Water Storage Tank 2011
T-809 400-bbl Condensate Storage Tank 2014
T-810 400-bbl Condensate Storage Tank 2014
T-811 400-bbl Produced Water Storage Tank 2007
Note: pressurized storage tanks and vapor recovery units are part of facility fugitive VOC
emissions
EUG-TO: Flares
EU Emission Unit Description Construction Date
TF-1 Emergency Flare – 0.13-MMBTUH 2011
SF-1 Stonewall Plant Emergency Flare – 0.13-MMBTUH 2014
EUG-AMINE: Amine Units
EU Emission Unit Description Construction Date
CAV-1 &
TAV-1
Amine Unit Still Vent (Coalgate Plant/Tupelo Plant) 2007/2011
19.5-MMBTUH Thermal Oxidizer 2015
SAV-1 &
SAV-2
Amine Unit Still Vent (Stonewall Plant 1/Stonewall Plant 2) 2014/2015
19.5-MMBTUH Thermal Oxidizer 2015
EUG-FUGS: Process Piping Fugitive Emissions
EU Emission Unit Description Construction Date
FUGS Process Piping Fugitive Emissions 2007-2011
PERMIT MEMORANDUM 2017-1011-TVR 6 DRAFT
SECTION IV. POTENTIAL EMISSIONS
Criteria Pollutants
Emissions were calculated using the following methods:
- Engine emissions were calculated using manufacturer emission factors for NOx, CO,
VOC, and formaldehyde with the use of dual catalytic converters or oxidation catalysts
(CO control approximately 90%; with uncontrolled factors of 0.44 g/hp-hr for the
G3516B engines and 0.26 g/hp-hr for the G3606LE and G3608LE engines, formaldehyde
control 90%) for all engines except the emergency generators. The emergency generator
emissions were based on 100 hours per year, while all other engines’ emissions were
based on 8,760 hours per year.
Engine ID Engine Type Formaldehyde
g/hp-hr
NOx
g/hp-hr
CO
g/hp-hr
VOC
g/hp-hr
REF And
C-1 to
C-7
1,478-hp Waukesha
L7042GSI with catalytic
converter
0.005 0.35 0.35 0.25
TC-1 and
TC-2
1,380-hp Caterpillar
G3516B with oxidative
catalyst
0.044 0.50 0.24 0.30
TC-4 to
TC-8
1,775-hp Caterpillar
G3606 LE with oxidative
catalyst
0.026 0.50 0.28 0.32
C-GEN T-
GEN
Kohler 1250REOZMB
(1,881-hp)
Kohler 1600REOZMB
(2,346-hp)
0.181
0.01 4.8 2.6 1.11
S-GEN1
S-GEN2
Kohler 1750REOZMB
(2,923-hp) 0.01 3.9 2.13 1.0
S-GEN3 Generac 58130 (23-hp) NA 10.0 387 10
SC-1 to
SC-6
2,370-hp Caterpillar
G3608 LE with oxidative
catalyst
0.026 0.50 0.19 0.32
- Emissions from the glycol reboilers and hot oil heaters are based on AP-42 (7/00),
Section 1.4. For H-781 and H-741, a 20% safety factor was added to AP-42 factors.
- Emissions from the Coalgate glycol dehydration unit were calculated using Gly-CALC
version 4.0, a recent gas analysis, a maximum natural gas processing capacity of 85
MMSCFD, and a glycol circulation rate of 27.6 GPM. The still vent is routed to the
“BTEX Eliminator”. Flash tank off-gases are shown in the Gly-Calc run as being vented
to the fuel gas and “BTEX Eliminator”. The reboiler has a continuous igniter to keep
burning VOC when the heater cycles off. The two methods have a control efficiency of
98%.
PERMIT MEMORANDUM 2017-1011-TVR 7 DRAFT
- Emissions from the Tupelo glycol dehydration unit were calculated using Gly-CALC
version 4.0, a recent gas analysis, a maximum natural gas processing capacity of 145
MMSCFD, and a glycol circulation rate of 27.6 GPM. The still vent is routed to the
“BTEX Eliminator”. The flash tank is vented to the fuel gas system and the “BTEX
Eliminator” with an overall 98% control.
- Emissions from the Stonewall Plant glycol dehydration units were calculated using Gly-
CALC version 4.0, a recent gas analysis, a maximum natural gas processing capacity of
130 MMSCFD and a glycol circulation rate of 30.3 GPM for Stonewall Unit 1. A
maximum natural gas processing capacity of 90 MMSCFD and a glycol circulation rate
of 15.5 GPM was used for Stonewall Unit 2. The still vents are routed to “BTEX
Eliminators”. Flash tank off-gases are shown in the Gly-Calc runs as being recovered and
recycled. The reboilers have continuous igniters to keep burning VOC when the heater
cycles off. The two methods have a control efficiency of 98%.
- Emergency flare emissions were calculated using Texas Commission on Environmental
Quality Guidance Document factors: 0.0969 lb/MMBTU NOx and 0.0814 lb/MMBTU
CO. Heat input of 0.13 MMBTUH was used for each flare.
- VOC emissions from each amine unit vent were calculated using BR&E PROMAX
simulations.
- Emissions from the atmospheric condensate tanks are controlled by a vapor recovery unit
(VRU) with 100% recovery.
Emissions from the Coalgate/Tupelo/Stonewall condensate truck loading operation were
calculated using 14,235,000 gallons per year throughput, 73 molecular weight, 0.60
saturation factor, and 3.86 psia vapor pressure, using the methods of AP-42 (1/95),
Section 5.2.
Loading
Operation Liquids Handled
Maximum
Annual
Throughput,
Gallons
Emission Factor
lb/1,000 gal
Reduction
Claimed
Wt.%
Coalgate
Stonewall
Tupelo
Condensate 14,235,000 4.05 -0-
- Emissions from the Coalgate/Tupelo/Stonewall condensate truck unloading are only from
the line being disconnected from the truck and were calculated based on 8,760 trucks per
year, a volume of 0.022 cu.ft., and a liquid density of 5.96 lb/gal.
- Emissions from fugitive equipment leaks are based on EPA’s document, “1995 Protocol
for Equipment Leak Emission Estimates,” Table 2-4, “Oil and Gas Operations Average
Emissions Factors” for process piping fugitives, and counts of components.
PERMIT MEMORANDUM 2017-1011-TVR 8 DRAFT
Facility-Wide Emissions
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
C-1, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-2, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-3, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-4, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-5, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-6, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-7, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-8, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-GEN, 1,881-hp Kohler 1250
REOZMB emergency generator 19.90 1.00 10.78 0.54 4.60 0.23
T-GEN, 2,346-hp Kohler 1600
REOZMB emergency generator 24.83 1.24 13.45 0.67 5.77 0.29
TC-1, 1,380-hp Caterpillar G3516B with
oxidative catalyst 1.52 6.66 0.74 3.24 1.05 4.58
TC-2, 1,380-hp Caterpillar G3516B with
oxidative catalyst 1.52 6.66 0.74 3.24 1.05 4.58
TC-4, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-5, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-6, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-7, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-8, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
SC-1, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SC-2, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SC-3, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
PERMIT MEMORANDUM 2017-1011-TVR 9 DRAFT
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
SC-4, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SC-6, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
S-GEN1, 2,923-hp Kohler 1750
REOZMB emergency generator 25.13 1.26 13.73 0.69 6.48 0.32
S-GEN2, 2,923-hp Kohler 1750
REOZMB emergency generator 25.13 1.26 13.73 0.69 6.48 0.32
S-GEN3, 23-hp Generac 58130
emergency generator 0.59 0.07 22.88 2.52 0.59 0.07
CH-1, 20 MMBTUH Hot Oil Heater 2.00 8.76 1.68 7.36 0.11 0.48
H-771, 19.45 MMBTUH Hot Oil Heater 1.95 8.52 1.63 7.16 0.11 0.47
H-781, 17.42 MMBTUH Hot Oil Heater 1.71 7.48 1.43 6.28 0.09 0.41
H-741, 5.61 MMBTUH Regen Heater 0.55 2.41 0.46 2.02 0.03 0.13
H-700, 5.5 MMBTUH Amine Unit
Heater 0.55 2.41 0.46 2.02 0.03 0.13
H-701, 12.15 MMBTUH Amine Unit
Heater 1.22 5.32 1.02 4.47 0.07 0.29
SA-1, 12.15 MMBTUH Amine Heater 1.22 5.32 1.02 4.47 0.07 0.29
SA-2, 10.08 MMBTUH Amine Heater 1.00 4.38 0.84 3.68 0.06 0.24
CRB-1, 2.0 MMBTUH Glycol Reboiler 0.20 0.88 0.17 0.74 0.01 0.05
TRB-1, 2.0 MMBTUH Glycol Reboiler 0.20 0.88 0.17 0.74 0.01 0.05
SRB-1, 1.5 MMBTUH Glycol Reboiler 0.15 0.66 0.13 0.55 0.01 0.03
SRB-2, 2.0 MMBTUH Glycol Reboiler 0.20 0.88 0.17 0.74 0.01 0.05
Condensate Tanks T-801 – T-810 -- -- -- -- * *
Condensate Truck Loading -- -- -- -- -- 29.27
UNLOAD, Condensate Truck
Unloading -- -- -- -- 0.02 0.09
FUGCT, Site Process Fugitives -- -- -- -- 5.01 21.96
FUGS, Site Process Fugitives -- -- -- -- 0.82 3.58
TF-1, Emergency Flare (0.13
MMBTUH) 0.02 0.06 0.01 0.05 0.03 0.13
SF-1, Emergency Flare (0.13
MMBTUH) 0.02 0.06 0.01 0.05 0.03 0.13
CTTO, Coalgate 19.5 MMBTUH
Thermal Oxidizer 4.88 21.36 5.85 25.63 0.10 0.44
STO, Stonewall 19.5 MMBTUH
Thermal Oxidizer 4.88 21.36 5.85 25.63 0.10 0.44
CSV-1, Coalgate Dehydration Unit and
BTEX Eliminator -- -- -- -- 2.17 9.51
TSV-1, Tupelo Dehydration Unit and
BTEX Eliminator -- -- -- -- 2.13 9.35
PERMIT MEMORANDUM 2017-1011-TVR 10 DRAFT
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
SSV-1, Dehydrator Still Vent -- -- -- -- 1.35 5.90
SSV-2, Dehydrator Still Vent -- -- -- -- 0.67 2.92
CAV-1, Coalgate Amine Unit Vent -- -- -- -- 0.06 0.27
TAV-1, Tupelo Amine Unit Vent -- -- -- -- 0.13 0.56
SAV-1, Coalgate Amine Still Vent -- -- -- -- 0.18 0.78
SAV-2, Coalgate Amine Still Vent -- -- -- -- 0.14 0.61
TOTAL EMISSIONS 151.44 249.58 116.52 189.93 61.59 195.81
*atmospheric condensate tanks are vented to vapor recovery units (VRUs), with only fugitive
emissions.
** emissions from pressurized tanks are a component of fugitive VOC leakage.
Hazardous Air Pollutants (HAP)
Dehydration units using glycol desiccants emit benzene, toluene, ethyl benzene, and xylene
(BTEX) and n-hexane from the glycol still vent. The applicant has analyzed the incoming wet
gas for concentrations of n-hexane and BTEX and estimated the HAP emissions using GRI-
GLYCalcTM.
Controlled Dehydration Unit HAP Emissions
HAP Coalgate Tupelo Stonewall
SSV-1
Stonewall
SSV-2 TOTALS
lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY
Benzene 0.085 0.374 0.078 0.331 0.064 0.280 0.032 0.142 0.259 1.127
Toluene 0.109 0.476 0.102 0.447 0.102 0.446 0.052 0.227 0.365 1.596
Ethyl Benzene 0.001 0.006 0.002 0.008 0.002 0.010 0.001 0.005 0.006 0.029
Xylene 0.046 0.204 0.053 0.231 0.065 0.283 0.034 0.148 0.198 0.866
n-Hexane 0.101 0.443 0.091 0.397 0.066 0.289 0.033 0.143 0.291 1.272
Totals 0.342 1.503 0.326 1.414 0.299 1.308 0.152 0.665 1.119 4.890
Controlled Amine Unit HAP Emissions
HAP Coalgate Tupelo Stonewall
SAV-1
Stonewall
SAV-2 TOTALS
lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY
Benzene 0.010 0.042 0.020 0.088 0.017 0.075 0.013 0.056 0.060 0.261
Toluene 0.017 0.073 0.038 0.167 0.046 0.200 0.035 0.152 0.135 0.592
Ethyl Benzene 0.001 0.001 0.001 0.003 0.002 0.008 0.001 0.006 0.004 0.019
Xylene 0.012 0.054 0.027 0.117 0.058 0.255 0.050 0.218 0.147 0.644
n-Hexane 0.001 0.004 0.001 0.004 0.001 0.004 0.001 0.003 0.003 0.015
Totals 0.040 0.174 0.086 0.379 0.124 0.541 0.099 0.435 0.349 1.530
PERMIT MEMORANDUM 2017-1011-TVR 11 DRAFT
The compressor engines have HAP emissions, the most significant being formaldehyde. The
table following lists estimated potential controlled formaldehyde emissions for the compressor
engines based on continuous operation. Control efficiency for formaldehyde was calculated at
79%.
Formaldehyde Emissions
Sources
Emission
Factor,
g/hp-hr
Formaldehyde
lbs/hr TPY
C-1, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-2, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-3, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-4, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-5, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-6, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-7, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
C-8, 1,478-hp Waukesha G-L7042GSI 0.005 0.02 0.07
SC-1, 2,370-hp Caterpillar G3608LE 0.026 0.14 0.60
SC-2, 2,370-hp Caterpillar G3608LE 0.026 0.14 0.60
SC-3, 2,370-hp Caterpillar G3608LE 0.026 0.14 0.60
SC-4, 2,370-hp Caterpillar G3608LE 0.026 0.14 0.60
SC-6, 2,370-hp Caterpillar G3608LE 0.026 0.14 0.60
TC-1, 1380-hp Caterpillar G3516B 0.044 0.13 0.59
TC-2, 1380-hp Caterpillar G3516B 0.044 0.13 0.59
TC-4, 1,775-hp Caterpillar G3606LE 0.026 0.10 0.45
TC-5, 1,775-hp Caterpillar G3606LE 0.026 0.10 0.45
TC-6, 1,775-hp Caterpillar G3606LE 0.026 0.10 0.45
TC-7, 1,775-hp Caterpillar G3606LE 0.026 0.10 0.45
TC-8, 1,775-hp Caterpillar G3606LE 0.026 0.10 0.45
C-GEN, 1,881-hp Kohler 1250REOZMB 0.181 0.75 0.04
T-GEN, 2,346-hp Kohler 1600REOZMB 0.01 0.03 0.01
S-GEN1, 2,923-hp Kohler 1750REOZMB 0.01 0.04 0.01
S-GEN2, 2,923-hp Kohler 1750REOZMB 0.01 0.04 0.01
S-GEN3, 23-hp Generac 58130 0.01 0.01 0.01
Totals 2.49 7.07
Emissions of each HAP are less than 10 TPY, and total HAP emissions are less than 25 TPY. The
facility is, therefore, an area source of HAPs.
Greenhouse Gas Emissions
Existing potential greenhouse gas emissions were stated at a total of 186,976 TPY CO2e. The
facility is a major source of GHG.
PERMIT MEMORANDUM 2017-1011-TVR 12 DRAFT
SECTION V. INSIGNIFICANT ACTIVITIES
The insignificant activities identified and justified in the application are duplicated below.
Records are available to confirm the insignificance of the activities. Appropriate recordkeeping
of activities indicated below with “*” is specified in the Specific Conditions.
1. * Space heaters, boilers, process heaters and emergency flares less than or equal to 5
MMBTUH heat input fired by commercial natural gas. The glycol reboiler heaters and
emergency flare are less than 5 MMBTUH.
2. Emissions from crude oil and condensate storage tanks with a capacity of less than or
equal to 420,000 gallons that store crude oil and condensate prior to custody transfer.
The condensate tanks store condensate prior to custody transfer and each has a capacity
of less than 420,000 gallons; however, since these tanks are to be vented to a VRU, no
records will be required.
3. * Emissions from storage tanks constructed with a capacity less than 39,894 gallons
which store a VOC with a vapor pressure less than 1.5 psia at maximum storage
temperature. All of the tanks at the facility, other than the condensate tanks, have
capacities less than 39,894 gallons and store products having a vapor pressure less than
1.5 psia.
SECTION VI. OKLAHOMA AIR POLLUTION CONTROL RULES
OAC 252:100-1 (General Provisions) [Applicable]
Subchapter 1 includes definitions but there are no regulatory requirements.
OAC 252:100-2 (Incorporation by Reference) [Applicable]
This subchapter incorporates by reference applicable provisions of Title 40 of the Code of
Federal Regulations. These requirements are addressed in the “Federal Regulations” section.
OAC 252:100-3 (Air Quality Standards and Increments) [Applicable]
Subchapter 3 enumerates the primary and secondary ambient air quality standards and the
significant deterioration increments. At this time, all of Oklahoma is in attainment of these
standards.
OAC 252:100-5 (Registration, Emission Inventory, and Annual Operating Fees) [Applicable]
Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission
inventories annually, and pay annual operating fees based upon total annual emissions of
regulated pollutants. The applicant will be required to submit an emissions inventory and submit
fees.
PERMIT MEMORANDUM 2017-1011-TVR 13 DRAFT
OAC 252:100-8 (Permits for Part 70 Sources) [Applicable]
Part 5 includes the general administrative requirements for Part 70 permits. Any planned
changes in the operation of the facility which result in emissions not authorized in the permit and
which exceed the “Insignificant Activities” or “Trivial Activities” thresholds require prior
notification to AQD and may require a permit modification. Insignificant activities mean
individual emission units that either are on the list in Appendix I (OAC 252:100), or whose
actual calendar year emissions do not exceed the following limits:
5 TPY of any one criteria pollutant
2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAP or 20% of
any threshold less than 10 TPY for single HAP that the EPA may establish by rule
Emission limitations and operational requirements necessary to assure compliance with all
applicable requirements for all sources are taken from the permit application, or developed from
the applicable requirements.
OAC 252:100-9 (Excess Emissions Reporting Requirements) [Applicable]
Except as provided in OAC 252:100-9-7(a)(1), the owner or operator of a source of excess
emissions shall notify the Director as soon as possible but no later than 4:30 p.m. the following
working day of the first occurrence of excess emissions in each excess emission event. No later
than thirty (30) calendar days after the start of any excess emission event, the owner or operator
of an air contaminant source from which excess emissions have occurred shall submit a report
for each excess emission event describing the extent of the event and the actions taken by the
owner or operator of the facility in response to this event. Request for mitigation, as described in
OAC 252:100-9-8, shall be included in the excess emission event report. Additional reporting
may be required in the case of ongoing emission events and in the case of excess emissions
reporting required by 40 CFR Parts 60, 61, or 63.
OAC 252:100-13 (Open Burning) [Applicable]
Open burning of refuse and other combustible material is prohibited except as authorized in the
specific examples and under the conditions listed in this subchapter.
OAC 252:100-19 (Control of Emission of Particulate Matter) [Applicable]
Section 19-4 regulates emissions of particulate matter (PM) from new and existing fuel-burning
equipment, with emission limits based on maximum design heat input rating. Fuel-burning
equipment is defined in OAC 252:100-1 as “combustion devices used to convert fuel or wastes
to usable heat or power.” Thus, the gas-fired heaters, reboilers, and engines are subject to the
requirements of this subchapter. The facility’s flares are not subject since they do not produce
any “usable heat or power”. Appendix C specifies a PM emission limitation range of 0.6
lb/MMBTU to 0.35 for fuel-burning equipment with a rated heat input range of 10 MMBTUH or
less up to 100 MMBTUH. AP-42 (7/98) Table 1.4-2 lists total PM emissions as 0.0076
lb/MMBTU for natural gas combustion. AP-42 (7/00) Section 3.2 lists total PM emissions from
natural gas-fired reciprocating internal combustion engines as about 0.01 lb/MMBTU. This
permit requires the use of natural gas for all fuel-burning units except for the emergency
generators to ensure compliance with Subchapter 19.
PERMIT MEMORANDUM 2017-1011-TVR 14 DRAFT
For the emergency generators, the TSP emissions are stated at 0.15 g/hp-hr (0.62 lb/hr). This is
equivalent to 0.049 lb/MMBTU, which is in compliance with the limitation of 0.58 lb/MMBTU.
OAC 252:100-25 (Visible Emissions and Particulates) [Applicable]
No discharge of greater than 20% opacity is allowed except for short-term occurrences that
consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed
three such periods in any consecutive 24 hours. In no case shall the average of any six-minute
period exceed 60% opacity. There is little possibility of exceeding these standards when burning
natural gas. This permit requires the use of natural gas for all fuel-burning units except the
emergency generators to ensure compliance with Subchapter 25.
OAC 252:100-29 (Control of Fugitive Dust) [Applicable]
No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the
property line on which the emissions originate in such a manner as to damage or to interfere with
the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the
maintenance of air quality standards. Under normal operating conditions, this facility has
negligible potential to violate this requirement; therefore, it is not necessary to require specific
precautions to be taken.
OAC 252:100-31 (Sulfur Compounds) [Applicable]
Part 2 limits the ambient air impact of hydrogen sulfide emissions from any new or existing
source to 0.2 ppm for a 24-hour average (equivalent to 280 g/m3). The gas processed at this
facility has negligible amounts of H2S, therefore, compliance with these standards is assured.
H2S emissions and impacts were based on a worst-case 4 ppm in inlet gas, with emission rates as
calculated by the mass balance, assuming all H2S is emitted at the amine units. For the Amine
Units, EPA SCREEN3 dispersion modeling was conducted based on the stack parameters listed
below. The 1-hour impacts predicted by SCREEN3 were converted to 24-hour impacts using a
factor of 0.4, as presented in “Screening Procedures for Estimating the Air Quality Impact from
Stationary Sources”, Revised (EPA-454/R-92-019). The SCREEN3 results are tabulated below.
Amine
Unit
Gas Rate
MMSCFD
H2S
Emissions
lb/hr*
Stack
Diam.
Ft
Stack
Height
Ft
Stack
Velocity
ft/sec
Stack
Temp oF
24-hour
Impacts
ug/m3
Coalgate 85 1.28 2.0 25 7.31 850 14
Tupelo 145 2.16 2.0 25 7.31 850 22
Stonewall 205 3.06 2.0 25 11.7 850 22
TOTALS 56 *These values are calculated assuming all H2S in the inlet gas is emitted from the amine units. According to
AMINECALC, only about half of the H2S is removed by the amine units. Measured H2S concentrations were 0.4
ppm at Stonewall, 1.0 ppm at Coalgate, and 0.64 ppm at Tupelo, all well below the worst-case concentration of H2S
of 4 ppm.
PERMIT MEMORANDUM 2017-1011-TVR 15 DRAFT
Part 5 limits sulfur dioxide emissions from new equipment (constructed after July 1, 1972). For
gaseous fuels, the limit is 0.2 lb/MMBTU heat input. For fuel gas having a gross calorific value
of 1,000 BTU/scf, this limit corresponds to a fuel sulfur content of approximately 1,200 ppmv.
Thus, a limitation of 343-ppmv sulfur in a field gas supply will be in compliance. The permit
requires the use of natural gas with a maximum sulfur content of 343-ppmv for all fuel-burning
equipment except the emergency generators to ensure compliance with Subchapter 31. For the
emergency generators, NSPS Subpart IIII limits the fuel sulfur content to 15 ppm, which is
equivalent to 0.015 lb/MMBTU. This emission rate is in compliance with the liquid fuel standard
of Subchapter 31 of 0.8 lb/MMBTU.
Part 5 also limits hydrogen sulfide (H2S) emissions from new petroleum or natural gas process
equipment (constructed after July 1, 1972). Removal of H2S in the exhaust stream, or oxidation
to sulfur dioxide (SO2), is required unless H2S emissions would be less than 0.3 lb/hr for a two-
hour average. With a maximum H2S concentration of 0.4 ppm in gas at Stonewall, 1 ppm in gas
at Coalgate, and 0.64 ppm in gas at Tupelo, the facility meets the 0.3 lb/hr exemption level.
OAC 252:100-33 (Nitrogen Oxides) [Not Applicable]
This subchapter limits new gas-fired fuel-burning equipment with rated heat input greater than or
equal to 50 MMBTUH to emissions of 0.2 lb of NOX per MMBTU, three-hour average. There
are no equipment items that equal or exceed the 50 MMBTUH threshold.
OAC 252:100-35 (Carbon Monoxide) [Not Applicable]
None of the following affected processes are located at this facility: gray iron cupola, blast
furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic
reforming unit.
OAC 252:100-37 (Volatile Organic Compounds) [Applicable]
Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of 400 gallons
or more and storing a VOC with a vapor pressure greater than 1.5 psia to be equipped with a
permanent submerged fill pipe or with an organic vapor recovery system. The condensate storage
tanks are subject to this requirement.
Part 3 requires loading facilities with a throughput equal to or less than 40,000 gallons per day to
be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the
vehicle is greater than 200 gallons. This facility does not have the physical equipment (loading
arm and pump) to conduct this type of loading. Therefore, this requirement is not applicable.
Part 7 requires fuel-burning equipment to be operated and maintained to minimize emissions of
VOC. All fuel-burning equipment at this location is subject to this requirement.
Part 7 regulates VOC/water separators that receive water containing more than 200 gallons per
day of VOC. There is no VOC/water separator at this facility.
OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable]
This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in
areas of concern (AOC). Any work practice, material substitution, or control equipment required
by the Department prior to June 11, 2004, to control a TAC, shall be retained unless a
modification is approved by the Director. Since no AOC has been designated anywhere in the
state, there are no specific requirements for this facility at this time.
PERMIT MEMORANDUM 2017-1011-TVR 16 DRAFT
OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable]
This subchapter provides general requirements for testing, monitoring and recordkeeping and
applies to any testing, monitoring or recordkeeping activity conducted at any stationary source.
To determine compliance with emissions limitations or standards, the Air Quality Director may
require the owner or operator of any source in the state of Oklahoma to install, maintain and
operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant
source. All required testing must be conducted by methods approved by the Air Quality Director
and under the direction of qualified personnel. A notice of intent to test and a testing protocol
shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests.
Emissions and other data required to demonstrate compliance with any federal or state emission
limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained,
and submitted as required by this subchapter, an applicable rule, or permit requirement. Data
from any required testing or monitoring not conducted in accordance with the provisions of this
subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive
use, of any credible evidence or information relevant to whether a source would have been in
compliance with applicable requirements if the appropriate performance or compliance test or
procedure had been performed.
The following Oklahoma Air Quality Rules are not applicable to this facility:
OAC 252:100-11 Alternative Emissions Reduction not eligible
OAC 252:100-15 Mobile Sources not in source category
OAC 252:100-17 Incinerators not type of emission unit
OAC 252:100-23 Cotton Gins not type of emission unit
OAC 252:100-24 Grain, Feed, or Seed Facility not in source category
OAC 252:100-39 Non-attainment Areas not in a subject area
OAC 252:100-47 Municipal Solid Waste Landfills not type of source category
SECTION VII. FEDERAL REGULATIONS
PSD, 40 CFR Part 52 [Not Applicable]
Total added potential emissions of regulated pollutants are less than the threshold level of 250
TPY.
NSPS, 40 CFR Part 60 [Subparts Dc, KKK, IIII, JJJJ, and OOOO Are Applicable]
Subpart Dc (Small Steam Generating Units) sets standards of performance for steam generating
units with a maximum design heat input capacity of 100 MMBTUH or less, but greater than 10
MMBTUH that were constructed after June 9, 1989. The natural gas-fired hot oil heaters (CH-1,
H-771, H-701, SA-1, SA-2, and H-781) are subject to this subpart. The only standard applicable
to gas-fired units is to keep records showing the amount of each fuel used. Subpart Dc excludes
“process heaters,” and the regeneration heaters do not meet the definition of “steam generating
unit” in Subpart Dc.
Subparts K, Ka, Kb, Volatile Organic Liquid (VOL) Storage Vessels. All tanks are below the
19, 813 gallon threshold for Subpart Kb.
PERMIT MEMORANDUM 2017-1011-TVR 17 DRAFT
Subpart GG, Stationary Gas Turbines. There are no stationary gas turbines at this facility.
Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants
constructed, reconstructed, or modified after January 20, 1984. This subpart sets standards for
natural gas processing plants, which are defined as any site engaged in the extraction of natural
gas liquids from field gas, fractionation of natural gas liquids, or both. The facility will be
subject to Subpart KKK once the gas plant is constructed. Subpart KKK specifically exempts
reciprocating compressors in wet gas service, and compressors that are not in VOC service, from
all but notification and recordkeeping requirements of §60.486(j) and §60.635(a) and (c). The
permittee will be required to maintain a leak detection and repair (LDAR) program for all
equipment that is “in VOC service” at the existing Coalgate and Tupelo Plants. New equipment at
the Stonewall Plant is subject to NSPS Subpart OOOO instead of Subpart KKK.
Subpart LLL, Onshore Natural Gas Processing: SO2 Emissions. This subpart sets standards for
natural gas sweetening units. Subpart LLL affects units which sweeten “sour” natural gas, which
is defined as gas having more than 4 ppm H2S. Since H2S is non-detectable in the inlet gas and
will be limited to 4 ppm, the amine units are not subject to Subpart LLL.
Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion
Engines, affects stationary compression ignition (CI) internal combustion engines (ICE) based on
power and displacement ratings, depending on date of construction, beginning with those
constructed after July 11, 2005. For the purposes of this subpart, the date that construction
commences is the date the engine is ordered by the owner or operator. Model year 2007 and later
engines which are not fire pump engines which have a cylinder displacement less than 10 liters
per cylinder and a rated capacity less than 3,000-hp are subject to the fuel sulfur limit of 60.4207,
the emissions limits of Table 1 to Subpart IIII for engines between 750 and 3,000-hp, and to
manufacturer certification requirements. C-GEN, T-GEN, S-GEN1 and S-GEN2 are subject.
Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI-ICE), promulgates
emission standards for all new SI engines ordered after June 12, 2006, and all SI engines
modified or reconstructed after June 12, 2006, regardless of size. The specific emission
standards (either in g/hp-hr or as a concentration limit) vary based on engine class, engine power
rating, lean-burn or rich-burn, fuel type, duty (emergency or non-emergency), and numerous
manufacture dates. The applicability date of rich-burn non-emergency spark-ignition engines is
July 1, 2007; all existing rich-burn engines were manufactured prior to this date. The new 1,380-
hp Caterpillar G3516B, 1,775-hp Caterpillar G3606 LE engines, and 2,370-hp Caterpillar
G3608LE engines are subject to the requirements of Subpart JJJJ. An initial performance test
must be conducted; in addition, engines that are greater than 500 HP must conduct a performance
test every 8,760 hours of operation or every 3 years thereafter, whichever comes first. Rich burn
engines operating with three-way catalysts or non-selective catalytic reduction must be equipped
with an air-to-fuel ratio controller operated in an appropriate manner to ensure proper operation
of the engine and control device in order to minimize emissions.
PERMIT MEMORANDUM 2017-1011-TVR 18 DRAFT
Engine
ID Description
Effective
Date
NOx CO VOC
g/hp-hr ppm * g/hp-hr ppm * g/hp-hr ppm *
TC-1 to
TC-2
1,380-hp Caterpillar
G3516B 7/1/07 2.0 160 4.0 540 1.0 86
TC-3 to
TC-8
1,775-hp Caterpillar
G3606 LE 7/1/07 2.0 160 4.0 540 1.0 86
SC-1 to
SC-6
2,370-hp Caterpillar
G3608LE 7/1/10 1.0 82 2.0 270 0.7 60
* corrected to 15% oxygen.
Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This
subpart was promulgated on August 16, 2012, and affects the following sources that commence
construction, reconstruction, or modification after August 23, 2011:
1. Each single gas well;
2. Single centrifugal compressors using wet seals that are located between the wellhead and
the point of custody transfer to the natural gas transmission and storage segment;
3. Reciprocating compressors which are single reciprocating compressors located between
the wellhead and the point of custody transfer to the natural gas transmission and storage
segment;
4. Single continuous bleed natural gas driven pneumatic controllers with a natural gas bleed
rate greater than 6 SCFH, which commenced construction after August 23, 2011, located
between the wellhead and the point of custody transfer to the natural gas transmission and
storage segment and not located at a natural gas processing plant;
5. Single continuous bleed natural gas driven pneumatic controllers which commenced
construction after August 23, 2011, and is located at a natural gas processing plant;
6. Single storage vessels located in the oil and natural gas production segment, natural gas
processing segment, or natural gas transmission and storage segment;
7. All equipment, except compressors, within a process unit at an onshore natural gas
processing plant;
8. Sweetening units located at onshore natural gas processing plants.
For each reciprocating compressor the owner/operator must replace the rod packing before
26,000 hours of operation or prior to 36 months. If utilizing the number of hours, the hours of
operation must be continuously monitored. Commenced construction is based on the date of
installation of the compressor (excluding relocation) at the facility. New (SC-1, SC-2, SC-3, SC-
4, and SC-6) or modified compressors will have to comply with this subpart.
There are no natural gas pneumatic controllers onsite.
Storage vessels constructed, modified or reconstructed after August 23, 2011, with VOC
emissions equal to or greater than 6 TPY must reduce VOC emissions by 95.0 % or greater. All
storage vessels utilize vapor recovery compressors, thus emissions are negligible and below the
6.0 TPY threshold.
PERMIT MEMORANDUM 2017-1011-TVR 19 DRAFT
The group of all equipment, except compressors, within a process unit at a natural gas processing
plant must comply with the requirements of NSPS, Subpart VVa, except as provided in
§60.5401. This standard affects the new Stonewall Plant.
A sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide
from the sour natural gas stream. There are two existing sweetening units at this facility but one
more has been added. Sweetening plants which process less than 2.0 LT/D sulfur are required to
comply only with recordkeeping requirements.
The permit will require the facility to comply with all applicable requirements of NSPS, Subpart
OOOO.
Subpart OOOOa, Standards of Performance for Crude Oil and Natural Gas Facilities for which
Construction, Modification or Reconstruction Commenced After September 18, 2015. This
subpart affects the following onshore facilities:
1. Well affected facilities
2. Centrifugal compressor affected facilities
3. Reciprocating compressor affected facilities
4. Pneumatic controller affected facilities
5. Pneumatic pump affected facilities
6. Storage vessel affected facilities
7. Fugitive emissions components at a well site and the collection of fugitive emissions
components at a compressor station
8. Onshore natural gas processing plants
9. Sweetening unit affected facilities
All equipment was constructed prior to the effective date of Subpart OOOOa.
NESHAP, 40 CFR Part 61 [Not Applicable]
There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene,
coke oven emissions, mercury, radionuclides, or vinyl chloride except for trace amounts of
benzene. Subpart J (Equipment Leaks of Benzene) concerns only process streams, which
contain more than 10% benzene by weight. All process streams at this facility are below this
threshold.
NESHAP, 40 CFR Part 63 [Subparts HH and ZZZZ are Applicable]
Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission
points that are located at facilities which are major sources of HAP, or TEG dehydration units
only located at an area source, and either process, upgrade, or store hydrocarbons prior to the
point of custody transfer or prior to which the natural gas enters the natural gas transmission and
storage source category. Subpart HH affects glycol dehydration unit process vents, storage
vessels with potential for flash emissions, and compressors and ancillary equipment (valves,
flanges, etc.) in VHAP service (i.e., more than 10% by weight HAP) that are located at gas
processing plants. This facility is taking a federally enforceable limit to remain a minor source
of HAP; therefore, only the TEG units are subject to Subpart HH. The applicant has also
PERMIT MEMORANDUM 2017-1011-TVR 20 DRAFT
requested a federally enforceable limit on benzene emissions from the TEG units of less than 1
TPY. The TEG units are exempt from the control requirements of Subpart HH by meeting the
exemption requirements of §63.764(e)(1) for actual annual benzene emissions below 1.0 TPY. The
facility is only subject to the emissions determinations and recordkeeping requirements of
§63.774(d)(1).
Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects any
existing, new, or reconstructed stationary RICE located at a major or area source of HAP
emissions. Owners and operators of the following new or reconstructed RICE must meet the
requirements of Subpart ZZZZ by complying with either 40 CFR Part 60 Subpart IIII (for CI
engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines):
1) Stationary RICE located at an area source;
2) The following Stationary RICE located at a major source of HAP emissions:
i) 2SLB and 4SRB stationary RICE with a site rating of ≤ 500 brake HP;
ii) 4SLB stationary RICE with a site rating of < 250 brake HP;
iii) Stationary RICE with a site rating of ≤ 500 brake HP which combust landfill or digester
gas equivalent to 10% or more of the gross heat input on an annual basis;
iv) Emergency or limited use stationary RICE with a site rating of ≤ 500 brake HP; and
v) CI stationary RICE with a site rating of ≤ 500 brake HP.
No further requirements apply for engines subject to NSPS under this part. Based on emission
calculations, this facility is a minor source of HAP. A stationary RICE located at an area source
of HAP emissions is new if construction commenced on or after June 12, 2006. The existing
engines at this facility were manufactured after June 12, 2006, and are still considered “new”
engines which are required to comply with NSPS Subpart JJJJ standards.
For the emergency engines, the facility will comply with Subpart ZZZZ by complying with
NSPS Subpart IIII.
Subpart JJJJJJ, National Emission Standards for Hazardous Air Pollutants for Industrial,
Commercial and Institutional Boilers at area sources of HAPs. The MACT was recently revised.
“Boiler” is defined as “an enclosed device using controlled flame combustion in which water is
heated to recover thermal energy in the form of steam and/or hot water. Controlled flame
combustion refers to a steady-state, or near steady-state, process wherein fuel and/or oxidizer
feed rates are controlled. A device combusting solid waste, as defined in § 241.3 of this chapter,
is not a boiler unless the device is exempt from the definition of a solid waste incineration unit as
provided in section 129(g)(1) of the Clean Air Act. Waste heat boilers, process heaters, and
autoclaves are excluded from the definition of Boiler.” The hot oil heaters and process heaters do
not meet the criteria of applicability.
PERMIT MEMORANDUM 2017-1011-TVR 21 DRAFT
CAM, 40 CFR Part 64 [Applicable]
Compliance Assurance Monitoring (CAM) applies to any pollutant specific emission unit at a
major source that is required to obtain a Title V permit, if it meets all of the following criteria:
1. It is subject to an emission limit or standard for an applicable regulated air pollutant.
2. It uses a control device to achieve compliance with the applicable emission limit or
standard.
3. It has potential emissions, prior to the control device, of the applicable regulated air
pollutant of 100 TPY for a criteria pollutant, 10 TPY for an individual HAP, or 25 TPY
for all HAP.
The compressor engines are all subject to NSPS Subpart JJJJ and/or NESHAP Subpart ZZZZ.
Under 40 CFR Part 60.64.2(b)(i), CAM does not affect emissions limits or standards proposed
by the Administrator after November 15, 1990, pursuant to Section 111 or 112 of the Act.
Based on the application, pre-control emissions of HAPs from the glycol dehydrators are above
10 TPY. The permit incorporates a CAM plan for the BTEX Eliminators.
Chemical Accident Prevention Provisions, 40 CFR Part 68 [Applicable]
This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant
and is subject to this Subpart (Section 112r of the Clean Air Act 1990 Amendments). A Risk
Management Plan was submitted to EPA Region 6 on July 7, 2008 and deemed complete on July
8, 2008. More information on this federal program is available on the web page:
www.epa.gov/rmp.
Stratospheric Ozone Protection, 40 CFR Part 82 [Subparts A and F are Applicable]
These standards require phase out of Class I & II substances, reductions of emissions of Class I
& II substances to the lowest achievable level in all use sectors, and banning use of nonessential
products containing ozone-depleting substances (Subparts A & C); control servicing of motor
vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations
which meet phase out requirements and which maximize the substitution of safe alternatives to
Class I and Class II substances (Subpart D); require warning labels on products made with or
containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon
disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds
under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons
(Subpart H).
Subpart A identifies ozone-depleting substances and divides them into two classes. Class I
controlled substances are divided into seven groups; the chemicals typically used by the
manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform
(Class I, Group V). A complete phase-out of production of Class I substances is required by
January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are
hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs.
Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances,
scheduled in phases starting by 2002, is required by January 1, 2030.
PERMIT MEMORANDUM 2017-1011-TVR 22 DRAFT
Subpart F requires that any persons servicing, maintaining, or repairing appliances except for
motor vehicle air conditioners; persons disposing of appliances, including motor vehicle air
conditioners; refrigerant reclaimers, appliance owners, and manufacturers of appliances and
recycling and recovery equipment comply with the standards for recycling and emissions
reduction.
This facility does not produce, consume, recycle, import, or export any controlled substances or
controlled products as defined in this part, nor does this facility perform service on motor (fleet)
vehicles that involves ozone-depleting substances. Therefore, as currently operated, this facility
is not subject to these requirements. To the extent that the facility has air-conditioning units that
apply, the permit requires compliance with Part 82.
SECTION VIII. COMPLIANCE
Testing
NSPS Subpart JJJJ testing was conducted on the engines subject to this subpart between
September 27 and October 4, 2017.
Engine
Load
During
Testing
NOx CO VOC
Emission
Limit,
g/hp-hr
Test
Result,
g/hp-hr
Emission
Limit,
g/hp-hr
Test
Result,
g/hp-hr
Emission
Limit,
g/hp-hr
Test
Result,
g/hp-hr
SC-1 90.2% 1.0 0.36 2.0 0.70 0.7 0.02
SC-2 90.2% 1.0 0.26 2.0 0.03 0.7 0.02
SC-3 90.2% 1.0 0.34 2.0 0.05 0.7 0.02
SC-4 90.2% 1.0 0.26 2.0 0.06 0.7 0.01
SC-6 90.6% 1.0 0.30 2.0 0.01 0.7 0.02
TC-1 90.6% 1.0 0.50 2.0 0.12 0.7 0.01
TC-2 93.1% 1.0 0.40 2.0 0.08 0.7 0.01
TC-4 90.1% 1.0 0.50 2.0 0.10 0.7 0.04
TC-5 90.5% 1.0 0.50 2.0 0.02 0.7 0.02
TC-6 90.7% 1.0 0.46 2.0 0.01 0.7 0.02
TC-7 90.4% 1.0 0.47 2.0 0.02 0.7 0.02
TC-8 90.1% 1.0 0..47 2.0 0.01 0.7 0.01
Tier Classification and Public Review
This application has been classified as Tier II based upon a request for renewal of a Title V
operating permit. Public review of the application and the permit are required.
The applicant published the “Notice of Filing a Tier II Application” in the Coalgate Record-
Register, a newspaper of general circulation in Coal County, on September 6, 2017. The notice
said that the application was available for public review at the Coal County Public Library, or at
the Oklahoma City AQD office. A draft of this permit will also be made available for public
review for a period of thirty days as will be stated in another published announcement. The
PERMIT MEMORANDUM 2017-1011-TVR 23 DRAFT
facility is located within 50 miles of the border with the state of Texas; the state of Texas will be
notified of the draft permit. The “proposed” permit will be submitted to EPA for a 45-day review
period.
The permittee has submitted an affidavit that they are not seeking a permit for any operation
upon land owned by others without their knowledge. The affidavit certifies that the applicant
owns the land.
Information on all permit action is available on the DEQ web page: www.deq.state.ok.us.
Fees Paid
Renewal of a Part 70 permit fee of $7,500.
SECTION IX. SUMMARY
The facility was constructed as described in the permit application. Ambient air quality standards
are not threatened at this site. There is an active Air Quality compliance or enforcement issue
concerning this facility which is unrelated to this permitting action. Issuance of the operating
permit is recommended, contingent on public and EPA review.
DRAFT
PERMIT TO OPERATE
AIR POLLUTION CONTROL FACILITY
SPECIFIC CONDITIONS
Targa Pipeline Mid-Continent LLC Permit Number 2017-1011-TVR
Coalgate/Tupelo/Stonewall Gas Plants
The permittee is authorized to operate in conformity with the specifications submitted to Air
Quality on July 3, 2017. The Evaluation Memorandum dated January 15, 2018, explains the
derivation of applicable permit requirements and estimates of emissions; however, it does not
contain operating limitations or permit requirements. Continuing operations under this permit
constitutes acceptance of, and consent to, the conditions contained herein:
1. Points of emissions and emissions limitations for each point: [OAC 252:100-8-6(a)(1)]
A. Emissions from engines (EUG COMP1 and EUG COMP2) are limited as follows.
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
C-1, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-2, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-3, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-4, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-5, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-6, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-7, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
C-8, 1,478-hp Waukesha L7042GSI
with Catalytic Converter 1.14 5.00 1.14 5.00 0.81 3.57
SC-1, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SC-2, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SC-3, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SC-4, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
SPECIFIC CONDITIONS 2017-1011-TVR 2 DRAFT
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
SC-6, Caterpillar G3608LE with
oxidative catalyst 2.61 11.44 0.99 4.34 1.78 7.80
TC-1, 1,380-hp Caterpillar G3516B with
oxidative catalyst 1.52 6.66 0.74 3.24 1.05 4.58
TC-2, 1,380-hp Caterpillar G3516B with
oxidative catalyst 1.52 6.66 0.74 3.24 1.05 4.58
TC-4, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-5, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-6, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-7, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
TC-8, 1,775-hp Caterpillar G3606LE
with oxidative catalyst 1.96 8.57 1.08 4.71 1.33 5.84
S-GEN3, 27-hp Generac 58130
Generator 0.59 0.07 22.88 2.52 0.59 0.07
i. Each engine at the facility shall have a permanent identification plate attached that is
accessible and legible, which shows the make, model number, and serial number.
[OAC 252:100-43]
ii. The permittee shall at all times properly operate and maintain all engines in a manner that
will minimize emissions of hydrocarbons or other organic materials.
[OAC 252:100-37-36]
iii. Engines C-1 to C-8 shall be equipped with non-selective catalytic converters to control
emissions of NOx, CO and HAP. Engines TC-1 to TC-8 shall be equipped with oxidative
catalysts to control emissions of VOC, CO, and HAPs. Engines SC-1 to SC-4 and SC-6
shall be equipped with oxidative catalysts or equivalent methods of CO, VOC, and HAP
emissions control. [OAC 252:100-8-5 (a)]
iv. The permittee shall keep operation and maintenance (O&M) records for each engine that
is not tested in a quarter. Such records shall at a minimum include the dates of operation
and maintenance and type of work performed. [OAC 252:100-8-6 (a)(3)(B)]
SPECIFIC CONDITIONS 2017-1011-TVR 3 DRAFT
v. At least once per calendar quarter, the permittee shall conduct tests of NOX and CO
emissions in exhaust gases from each engine and from each replacement engine/turbine
when operating under representative conditions for that period. Testing is required for
each engine or any replacement engine/turbine that runs for more than 220 hours during
that calendar quarter. A quarterly test may be conducted no sooner than 20 calendar days
after the most recent test. Testing shall be conducted using a portable analyzer in
accordance with a protocol meeting the requirements of the latest AQD Portable
Analyzer Guidance document, or an equivalent method approved by Air Quality. When
four consecutive quarterly tests show the engine/turbine to be in compliance with the
emissions limitations shown in the permit, then the testing frequency may be reduced to
semi-annual testing. A semi-annual test may be conducted no sooner than 60 calendar
days nor later than 180 calendar days after the most recent test. Likewise, when the
following two consecutive semi-annual tests show compliance, the testing frequency may
be reduced to annual testing. An annual test may be conducted no sooner than 120
calendar days nor later than 365 calendar days after the most recent test. Upon any
showing of non-compliance with emissions limitations or testing that indicates that
emissions are within 10% of the emission limitations, the testing frequency shall revert to
quarterly. Reduced testing frequency does not apply to engines with catalytic converters.
Any reduction in the testing frequency shall be noted in the next required compliance
certification. [OAC 252:100-8-6 (a)(3)(A)]
vi. When periodic compliance testing shows exhaust emissions from the engines in excess of
the lb/hr limits in Specific Condition No. 1, the permittee shall comply with the
provisions of OAC 252:100-9. [OAC 252:100-9]
vii. Replacement (including temporary periods of 6 months or less for maintenance purposes)
of internal combustion engines/turbines with emissions limitations specified in this
permit with engines/turbines of lesser or equal emissions of each pollutant (in lb/hr and
TPY) are authorized under the following conditions. [OAC 252:100-8-6 (a)(3)(A)]
a. The permittee shall notify AQD in writing not later than 7 days in advance of the
start-up of the replacement engine(s)/turbine(s). Said notice shall identify the
equipment removed and shall include the new engine/turbine make, model, and
horsepower; date of the change, and any change in emissions.
b. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be conducted
to confirm continued compliance with NOX and CO emission limitations. A copy of
the first quarter testing shall be provided to AQD within 60 days of start-up of each
replacement engine/turbine. The test report shall include the engine/turbine fuel
usage, serial number, stack flow (ACFM), stack temperature (oF), stack height (feet),
stack diameter (inches), and pollutant emission rates (g/hp-hr, lbs/hr, and TPY) at
maximum rated horsepower for the altitude/location.
SPECIFIC CONDITIONS 2017-1011-TVR 4 DRAFT
c. Replacement equipment and emissions are limited to equipment and emissions which
are not a modification under NSPS or NESHAP, or a significant modification under
PSD. For existing PSD facilities, the permittee shall calculate the PTE or the net
emissions increase resulting from the replacement to document that it does not exceed
significance levels and submit the results with the notice required by a. of this
Specific Condition.
d. Engines installed as allowed under the replacement allowances in this Specific
Condition that are subject to 40 CFR Part 63, Subpart ZZZZ and/or 40 CFR Part 60,
Subpart JJJJ shall comply with all applicable requirements.
viii. The owner/operator shall comply with all applicable requirements of the NESHAP for
Stationary Reciprocating Internal Combustion Engines (RICE), Subpart ZZZZ, including
but not limited to: [40 CFR 60.630 to 60.636]
a. § 63.6580 What is the purpose of subpart ZZZZ?
b. § 63.6585 Am I subject to this subpart?
c. § 63.6590 What parts of my plant does this subpart cover?
d. § 63.6595 When do I have to comply with this subpart?
e. § 63.6600 What emission limitations and operating limitations must I meet?
f. § 63.6605 What are my general requirements for complying with this subpart?
g. § 63.6610 By what date must I conduct the initial performance tests or other initial
compliance demonstrations?
h. § 63.6615 When must I conduct subsequent performance tests?
i. § 63.6620 What performance tests and other procedures must I use?
j. § 63.6625 What are my monitoring, installation, operation, and maintenance
requirements?
k. § 63.6630 How do I demonstrate initial compliance with the emission limitations and
operating limitations?
l. § 63.6635 How do I monitor and collect data to demonstrate continuous compliance?
m. § 63.6640 How do I demonstrate continuous compliance with the emission limitations
and operating limitations?
n. § 63.6645 What notifications must I submit and when?
SPECIFIC CONDITIONS 2017-1011-TVR 5 DRAFT
o. § 63.6650 What reports must I submit and when?
p. § 63.6655 What records must I keep?
q. § 63.6660 In what form and how long must I keep my records?
r. § 63.6665 What parts of the General Provisions apply to me?
s. § 63.6670 Who implements and enforces this subpart?
t. § 63.6675 What definitions apply to this subpart?
ix. The permittee shall comply with all applicable requirements in 40 CFR Part 60 Subpart
JJJJ for stationary spark ignition (SI) internal combustion engines (ICE) Engines TC-1 to
TC-8, SC-1 to SC-4, SC-6, and S-GEN3including, but not limited to, the following.
[40 CFR §§ 60.4230 to 60.4246]
a. §60.4230 Am I subject to this subpart? Any of the engines ordered after June 12,
2006 with a maximum engine power of greater than 1,350 HP that are manufactured
after July 1, 2007 are subject to this subpart. Any of the engines ordered after June
12, 2006 with a maximum engine power less than 1,350 HP that are manufactured
after January 1, 2008 are subject to this subpart.
b. The emission standards of §60.4233 and §60.4234.
c. The fuel requirements of §60.4235 for gasoline fired engines.
d. The deadlines for importing or installing SI ICE produced in the previous model year
in accordance with §60.4236.
e. The monitoring requirements of §60.4237 for emergency engines.
f. The compliance requirements of §60.4243.
g. The performance test methods and other procedures of §60.4244.
h. The notification, reporting, and recordkeeping requirements of §60.4245.
i. §60.4246 What parts of the General Provisions apply to me?
j. §60.4248 What definitions apply to this subpart?
SPECIFIC CONDITIONS 2017-1011-TVR 6 DRAFT
B. Emissions from engines (EUG EMRGEN) are limited as follows.
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
C-GEN, 1,881-hp Kohler 1250
REOZMB emergency generator
(Coalgate)
19.90 1.00 10.78 0.54 4.60 0.23
T-GEN, 2,346-hp Kohler 1600
REOZMB emergency generator
(Tupelo)
24.83 1.24 13.45 0.67 5.77 0.29
S-GEN1, 2,923-hp Kohler 1750
REOZMB emergency generator 25.13 1.26 13.73 0.69 6.48 0.32
S-GEN2, 2,923-hp Kohler 1750
REOZMB emergency generator 25.13 1.26 13.73 0.69 6.48 0.32
i. The engines shall have a permanent identification plate attached that is accessible and
legible, which shows the make, model number, and serial number. [OAC 252:100-43]
ii. The permittee shall at all times properly operate and maintain the engines in a manner
that will minimize emissions of hydrocarbons or other organic materials.
[OAC 252:100-37-36]
iii. Except for emergency usages, the engines shall not be operated more than 100 hours per
year. [OAC 252:100-8-6 (a)(3)(A)]
iv. The emergency engines are subject to 40 CFR Part 60, Subpart IIII, and shall comply with
applicable standards for non-fire pump engines with cylinder displacements less than 10
liters and rated powers less than 3,000 hp with a model year of 2007 or later.
a. The engines must be certified by the manufacturer per 40 CFR Part 60.4201 and
4202.
b. The engines shall comply with applicable emissions limitations of 40 CFR 60.4204
and Table 1 to Subpart IIII.
c. The fuel used shall meet the requirements of 40 CFR Part 60.4207.
d. A non-resettable run-hour meter shall be installed per 40 CFR Part 60.4209(a)
SPECIFIC CONDITIONS 2017-1011-TVR 7 DRAFT
C. Emissions from the Hot Oil Heaters are limited as follows.
Source NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
CH-1, 20 MMBTUH Hot Oil Heater 2.00 8.76 1.68 7.36 0.11 0.48
H-771, 19.45 MMBTUH Hot Oil Heater 1.95 8.52 1.63 7.16 0.11 0.47
H-701, 12.15 MMBTUH Amine Heater 1.22 5.32 1.02 4.47 0.07 0.29
H-781, 17.42 MMBTUH Hot Oil Heater 2.25 9.84 1.89 8.26 0.12 0.54
SA-1, 12.15 MMBTUH Amine Heater 1.22 5.32 1.02 4.47 0.07 0.29
SA-2, 10.8 MMBTUH Amine Heater 1.00 4.38 0.84 3.68 0.06 0.24
i. The hot oil heaters are subject to federal New Source Performance Standards, 40 CFR 60,
Subpart Dc, and shall comply with all applicable requirements. These requirements include
keeping records of fuel consumed (natural gas) to demonstrate that no emissions limitations
of the subpart are applicable. [40 CFR Part 60.49c(g)]
D. Emissions from the Amine Units (EUG AMINE) are limited as follows:
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
CAV-1, Coalgate Amine Unit Still Vent -- -- -- -- 0.06 0.27
TAV-1, Tupelo Amine Unit Still Vent -- -- -- -- 0.13 0.56
SAV-1, Amine Still Vent -- -- -- -- 0.17 0.75
SAV-2, Stonewall Amine Unit -- -- -- -- 0.16 0.70
CTTO-1, 19.5 MMBTUH Thermal
Oxidizer 4.88 21.26 5.85 25.63 0.03 0.13
STO-1, 19.5 MMBTUH Thermal
Oxidizer 4.88 21.26 5.85 25.63 0.03 0.13
i. H2S concentrations of the inlet gas shall not exceed 4.0 ppm, when any amine unit is in
operation. [OAC 252:100-31 and 40 CFR 60 Subpart LLL]
ii. If an amine unit operates during a calendar year, then at least once per calendar year, the
permittee shall analyze the natural gas being processed for H2S and other sulfur compounds.
[OAC 252:100-43]
iii. Circulation rate of amine shall not exceed 135 GPM at the Coalgate Plant unit or 165
GPM at the Tupelo Plant unit and shall not exceed 165 GPM apiece at the Stonewall Plant
unit respectively. If the manufacturer’s rating is visible on the pump, or performance data for
the model of pump that verifies the maximum pump rate is less than this level, monitoring of
pump operating rate shall not be required. Otherwise, the amine circulation rate shall be
monitored and recorded at least once every calendar month. The amine circulation rate shall
be recorded for each inspection as follows.
SPECIFIC CONDITIONS 2017-1011-TVR 8 DRAFT
Circulation rate, as found (gal/min, strokes/min) __________
Circulation rate, as left (gal/min, strokes/min) __________
Date of inspection __________
Inspected by __________
iv. All H2S concentrations measured for Specific Condition No. 1.D shall be conducted using
a Draeger tube or approved alternative. The resolution of the Draeger tube or alternative shall
be at least 0.5 ppm H2S.
v. Measurements of sulfur compounds shall be used to demonstrate compliance with the 100
lb/hr SO2 limitation of OAC 252:100-31-26(2).
vi. All VOC and HAP discharges from the amine units must be routed to a thermal oxidizer,
or equivalent system that reduces VOC and HAP discharges by 98%.
E. The equipment listed below (EUG INSIG HTR) do not have any specific emission
limitations.
EU Description
H-700 5.5 MMBTUH Hot Oil Heater (Tupelo Plant)
CRB-1 2.0-MMBTUH Glycol Dehydrator Reboiler
TRB-1 2.0-MMBTUH Glycol Dehydrator Reboiler
H-741 5.61-MMBTUH Mole Sieve Regenerator (Stonewall Plant)
SRB-1 1.5-MMBTUH Glycol Dehydrator Reboiler
SRB-2 2.0-MMBTUH Glycol Dehydrator Reboiler
F. Emissions from the storage tanks (EUG TANK) are limited as follows.
i. Discharges of VOC from the atmospheric condensate tanks shall be controlled by a vapor
recovery unit (VRU) and returned to the process. There is no limit to throughput of
condensate tanks. [OAC 252:100-37-15(a)(2) & OAC 252:100-37-15(b)]
ii. Natural gas liquids as extracted from field gas shall be stored only in tanks which are
capable of maintaining working pressures above 30 psia. There is no limit to throughput
of pressure tanks.
SPECIFIC CONDITIONS 2017-1011-TVR 9 DRAFT
G. Emissions from the Emergency Flares (EUG TO) are limited as follows.
Sources NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
TF-1, Emergency Flare (0.13
MMBTUH) 0.02 0.06 0.01 0.05 0.01 0.07
SF-1, Emergency Flare (0.13
MMBTUH) 0.02 0.06 0.01 0.05 0.01 0.07
i. Whenever the emergency flare is processing VOC discharges, the unit shall be monitored
for the presence of a pilot flame.
H. Fugitive VOC Leakage for the Coalgate and Tupelo Plants (FUGCT and FUGS): the
permittee shall comply with the following standards of NSPS Subpart KKK. For the
Stonewall Plant, the permittee shall comply with the applicable provisions of NSPS Subpart
OOOO.
i. The owner operator shall comply with the requirements of §§ 60.482-1(a), (b), and (d)
and § 60.482-2 through § 60.482-10 except as provided in § 60.633:
a. The operator shall demonstrate compliance with §§ 60.482-1 to 60.482-10 for all
affected equipment within 180 days of initial startup which shall be determined by
review of records, reports, performance test results, and inspection using methods
and procedures specified in § 60.485 unless the equipment is in vacuum service and
is identified as required by § 60.486(e)(5).
b. The owner operator shall comply with the monitoring, inspection, and repair
requirements, for pumps in light liquid service, of §§ 60.482-2(a), (b), and (c) except
as provided in §§ 60-482-2(d), (e), and (f).
c. Each compressor shall be equipped with a seal system that includes a barrier fluid
system and that prevents leakage of VOC to the atmosphere, except as provided in §
60.632(c), § 60.633(f), § 60.482-1(c), § 60.482-3(h), and § 60.482-3(i).
i) Each compressor seal system shall comply with the requirements of §§ 60.482-
3(b).
ii) Each barrier fluid system shall be equipped with a sensor as required by §
60.482-3(d) that is monitored or equipped with an alarm as required by §
60.482-3(e) and repaired as required by §§ 60.482-3(f) and (g).
SPECIFIC CONDITIONS 2017-1011-TVR 10 DRAFT
d. Any existing reciprocating compressor in a process unit which becomes an affected
facility under provisions of § 60.14 or § 60.15 is exempt from §§ 60.482(a), (b), (c),
(d), (e), and (h), provided the owner or operator demonstrates that recasting the
distance piece or replacing the compressor are the only options available to bring the
compressor into compliance with the provisions of §§ 60.482-3(a) through (e) and
(h).
e. The owner operator shall comply with the operation and monitoring requirements, for
pressure relief devices in gas/vapor service, of §§ 60.482-4(a) and (b) except as
provided in § 60-482-4(c) and § 60.633(b).
f. Sampling and connection systems are exempt from the requirements of § 60.482-5.
g. Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a
second valve, except as provided in § 60.632(c). The cap, blind flange, plug, or
second valve shall seal the open end at all times except during operations requiring
process fluid flow through the open-ended valve or line. Each open-ended valve or
line equipped with a second valve shall be operated in a manner such that the valve
on the process fluid end is closed before the second valve is closed. When a double
block-and-bleed system is being used, the bleed valve or line may remain open during
operations that require venting the line between the block valves but shall be closed at
all other times.
h. The owner operator shall comply with the monitoring, inspection, and repair
requirements, for valves in gas/vapor service and light liquid service, of §§ 60.482-
7(b) through (e), except as provided in §§ 60.633(d), 60.482-7(f), (g), and (h), §§
60.483-1, 60.483-2, and 60.482-1(c).
i. The owner operator shall comply with the monitoring and repair requirements, for
pumps and valves in heavy liquid service, pressure relief devices in light liquid or
heavy liquid service, and flanges and other connectors, of §§ 60.482-8(a) through (d).
j. Delay of repair of equipment is allowed if it meets one of the requirements of §§
60.482-9(a) through (e).
k. The owner or operators using a closed vent system and control device to comply with
these provisions shall comply with the design, operation, monitoring and other
requirements of 60.482-10(b) through (g).
l. An owner or operator may elect to comply with the alternative requirements for
valves of §§ 60.483-1 and 60.483-2.
SPECIFIC CONDITIONS 2017-1011-TVR 11 DRAFT
m. An owner or operator may apply to the Administrator for permission to use an
alternative means of emission limitation that achieves a reduction in emissions of
VOC at least equivalent to that achieved by the controls required in NSPS Subpart
KKK. In doing so, the owner or operator shall comply with requirements of §
60.634.
n. Each owner or operator subject to the provisions of NSPS Subpart KKK shall comply
with the test method and procedures of § 60.485 except as provided in §§ 60.632(f)
and 60.633(h).
o. Each owner or operator subject to the provisions of NSPS Subpart KKK shall comply
with the recordkeeping requirements of § 60.486 and the reporting requirements of §
60.487 except as provided in §§ 60.633, 60.635, and 60.636.
p. Each owner or operator subject to the provisions of NSPS Subpart KKK shall comply
with the recordkeeping requirements of §§ 60.635(b) and (c) in addition to the
requirements of § 60.486.
q. Each owner or operator subject to the provisions of NSPS Subpart KKK shall comply
with the reporting requirements of §§ 60.636(b) and (c) in addition to the
requirements of § 60.487.
I. Emissions from the glycol dehydrators (EUG DEHY) are limited as follows.
Sources VOC Benzene
lb/hr TPY TPY
CSV-1, Coalgate Plant Dehydration Unit
and BTEX Eliminator 2.17 9.51 0.99
TSV-1, Tupelo Dehydration Unit and
BTEX Eliminator 2.13 9.35 0.99
SSV-1, Stonewall Plant Dehydration
Unit and BTEX Eliminator 1.32 5.76 0.99
SSV-2, Stonewall Plant Dehydration
Unit and BTEX Eliminator 0.67 2.92 0.99
i. Still vent and flash tank discharges from each dehydration unit shall be processed by a
condenser or equivalent device. VOC emissions from the control device shall be vented
to a combustion unit with a continuous igniter or recycled to the process. Alternatively,
VOC discharges from the dehydration units’ still vents and flash tanks may be recycled to
the process or processed by a combustion unit with 98% or higher control efficiency for
VOC.
SPECIFIC CONDITIONS 2017-1011-TVR 12 DRAFT
ii. The natural gas throughput of the Coalgate glycol dehydration unit shall not exceed 85
MMSCFD, monthly average. The natural gas throughput of the Tupelo glycol
dehydration unit shall not exceed 145 MMSCFD, monthly average. The natural gas
throughput of the Stonewall glycol dehydration units combined shall not exceed 220
MMSCFD, monthly average.
iii. The lean glycol circulation rate of each dehydration unit at Coalgate and Tupelo shall not
exceed 27.6 gallons per minute. The lean glycol circulation rate of the 130 MMSCFD
dehydration unit at Stonewall shall not exceed 30.3 gallons per minute. The lean glycol
circulation rate for the 90 MMSCFD dehydration unit at Stonewall shall not exceed 15.5
gallons per minute. If the manufacturer’s rating is visible on the pump, or performance
data for the model of pump that verifies the maximum pump rate is less than this level,
monitoring of pump operating rate shall not be required. Otherwise, the glycol circulation
rate shall be monitored and recorded at least once every calendar month. The lean glycol
circulation rate shall be recorded for each inspection as follows.
Circulation rate, as found (gal/min, strokes/min) __________
Circulation rate, as left (gal/min, strokes/min) __________
Date of inspection __________
Inspected by __________
iv. The glycol dehydration units are subject to 40 CFR Part 63 Subpart HH and shall comply
with all applicable requirements including, but not limited to, the following.
[40 CFR §63.760 – §63.775]
a. The permittee shall determine actual average benzene emissions using the model
GRI-GLYCalc™ Version 3.0 or higher in accordance with 40 CFR 63.772(b)(2).
Inputs to the model shall be representative of actual operating conditions.
b. The permittee maintain records of actual average benzene emissions in accordance
with 40 CFR 63.774(d)(1)(ii).
J. Emissions from the truck loading operations (EUG CONDLOAD) are limited as follows.
EU Description VOC
TPY
LOAD Stonewall/Coalgate/Tupelo Truck
Loading 29.27
UNLOAD Condensate Truck Unloading 0.09
i. Throughput of the unpressurized truck loading shall not exceed a total of 14,235,000
gallons in any 12-month period.
SPECIFIC CONDITIONS 2017-1011-TVR 13 DRAFT
2. Except for the emergency generator engines, the fuel-burning equipment shall be fired with
pipeline grade natural gas or other gaseous fuel with a sulfur content less than 343-ppmv.
Compliance can be shown by the following methods: for gaseous fuel, a current gas company
bill, lab analysis, stain-tube analysis, gas contract, tariff sheet, or other approved methods.
Compliance shall be demonstrated at least once per calendar year. [OAC 252:100-8-6(a)]
3. The permittee shall be authorized to operate this facility continuously (24 hours per day, every
day of the year). [OAC 252:100-8-6(a)]
4. The following records shall be maintained on-site to verify Insignificant Activities. No
recordkeeping is required for those operations that qualify as Trivial Activities.
[OAC 252:100-8-6 (a)(3)(B)]
A. For space heaters, boilers, process heaters, and emergency flares less than or equal to 5
MMBTUH heat input fired by commercial natural gas: records of design heat input and
type of gas fired.
B. For emissions from storage tanks constructed with a capacity less than 39,894 gallons
which store VOC with a vapor pressure less than 1.5 psia at maximum storage
temperature: records of tank capacity and true vapor pressure at maximum storage
temperature.
C. For activities having the potential to emit no more than 5 TPY (actual) of any criteria
pollutant: records of the type of activity and the amount of emissions from that activity
(annual).
5. The permittee shall comply with NSPS, Subpart OOOO, Standards of Performance for
Crude Oil and Natural Gas Production, Transportation, and Distribution, for all affected facilities
located at this site.
A. § 60.5360 What is the purpose of this subpart?
B. § 60.5365 Am I subject to this subpart?
C. § 60.5370 When must I comply with this subpart?
D. § 60.5375 What standards apply to gas well affected facilities?
E. § 60.5380 What standards apply to centrifugal compressor affected facilities?
F. § 60.5385 What standards apply to reciprocating compressor affected facilities?
G. § 60.5390 What standards apply to pneumatic controller affected facilities?
H. § 60.5395 What standards apply to storage vessel affected facilities?
SPECIFIC CONDITIONS 2017-1011-TVR 14 DRAFT
I. § 60.5400 What equipment leak standards apply to affected facilities at an onshore
natural gas processing plant?
J. § 60.5401 What are the exceptions to the equipment leak standards for affected
facilities at onshore natural gas processing plants?
K. § 60.5402 What are the alternative emission limitations for equipment leaks from
onshore natural gas processing plants?
L. § 60.5405 What standards apply to sweetening units at onshore natural gas processing
plants?
M. § 60.5406 What test methods and procedures must I use for my sweetening units
affected facilities at onshore natural gas processing plants?
N. § 60.5407 What are the requirements for monitoring of emissions and operations from
my sweetening unit affected facilities at onshore natural gas processing plants?
O. § 60.5408 What is an optional procedure for measuring hydrogen sulfide in acid gas-
Tutwiler Procedure?
P. § 60.5410 How do I demonstrate initial compliance with the standards for my gas
well affected facility, my centrifugal compressor affected facility, my reciprocating
compressor affected facility, my pneumatic controller affected facility, my storage
vessel affected facility, and my equipment leaks and sweetening unit affected
facilities at onshore natural gas processing plants?
Q. § 60.5411 What additional requirements must I meet to determine initial compliance
for my closed vent systems routing emissions from storage vessels or centrifugal
compressor wet seal fluid degassing systems?
R. § 60.5412 What additional requirements must I meet for determining initial
compliance with control devices used to comply with the emission standards for my
storage vessel or centrifugal compressor affected facility?
S. § 60.5413 What are the performance testing procedures for control devices used to
demonstrate compliance at my storage vessel or centrifugal compressor affected
facility?
T. § 60.5415 How do I demonstrate continuous compliance with the standards for my
gas well affected facility, my centrifugal compressor affected facility, my stationary
reciprocating compressor affected facility, my pneumatic controller affected facility,
my storage vessel affected facility, and my affected facilities at onshore natural gas
processing plants?
SPECIFIC CONDITIONS 2017-1011-TVR 15 DRAFT
U. § 60.5416 What are the initial and continuous cover and closed vent system
inspection and monitoring requirements for my storage vessel or centrifugal
compressor affected facility?
V. § 60.5417 What are the continuous control device monitoring requirements for my
storage vessel or centrifugal compressor affected facility?
W. § 60.5420 What are my notification, reporting, and recordkeeping requirements?
X. § 60.5421 What are my additional recordkeeping requirements for my affected
facility subject to VOC requirements for onshore natural gas processing plants?
Y. § 60.5422 What are my additional reporting requirements for my affected facility
subject to VOC requirements for onshore natural gas processing plants?
Z. § 60.5423 What additional recordkeeping and reporting requirements apply to my
sweetening unit affected facilities at onshore natural gas processing plants?
AA. § 60.5425 What parts of the General Provisions apply to me?
BB. § 60.5430 What definitions apply to this subpart?
6. The permittee shall maintain records of operations as listed below. These records shall be
maintained on-site for at least five years after the date of recording and shall be provided to
regulatory personnel upon request. [OAC 252:100-43]
A. O&M records for any engine, if operated less than 220 hours per quarter and not tested.
B. Periodic testing for NOX and CO for each engine.
C. For the fuel burned the appropriate document(s) as described in Specific Condition No. 2.
D. Records required by 40 CFR §60, Subparts KKK and OOOO, including, but not limited
to, records demonstrating that a reciprocating compressor is in wet gas service or is not in
VOC service, records demonstrating that equipment components are not in VOC service,
and records required by LDAR program provisions.
E. Truck loading operation condensate throughput (monthly and 12-month rolling total).
F. Records required by NESHAP Subpart HH for the glycol dehydrators.
G. Records required by NSPS Subparts IIII and JJJJ, and NESHAP Subpart ZZZZ.
H. Inlet H2S testing (annual).
I. Records as required by NSPS Subpart Dc for fuels burned in the hot oil heaters.
SPECIFIC CONDITIONS 2017-1011-TVR 16 DRAFT
J. Amine circulation rates (monthly if amine units operated).
K. Dehydration unit gas throughputs and glycol circulation rates (monthly).
L. When inlet gas H2S concentrations exceed 1 ppm for Coalgate or 0.4 ppm for Tupelo,
records of amine unit discharge flows, H2S concentrations, and calculations of H2S
discharge rates (monthly).
7. No later than 30 days after each anniversary date of the issuance of the initial Title V
operating permit for this facility (January 2, 2013), the permittee shall submit to Air Quality
Division of DEQ, with a copy to the US EPA, Region 6, a certification of compliance with the
terms and conditions of this permit. [OAC 252:100-8-6 (c)(5)(a)&(d)]
8. On issuance, Permit No. 2017-1011-TVR replaces and supersedes Permit No. 2006-309-TV
(M-9).
Targa Pipeline Mid-Continent LLC
Ms. Catherine Schroder
14000 Quail Springs Parkway, Suite 215
Oklahoma City, OK 73134
SUBJECT: Permit No. 2017-1011-TVR
Coalgate, Tupelo, and Stonewall Gas Plants (FAC ID 6265)
Section 6, T1S, R10E, Coal County, Oklahoma
Dear Ms. Schroder:
Enclosed is the permit authorizing operation of the referenced facility. Please note that this
permit is issued subject to standard and specific conditions that are attached. These conditions
must be carefully followed since they define the limits of the permit and will be confirmed by
periodic inspections.
Also note that you are required to submit an emissions inventory for this facility. An emissions
inventory must be completed on approved AQD forms and submitted (hardcopy or
electronically) by April 1st of every year. Any questions concerning the form or submittal
process should be referred to the Emissions Inventory Staff at 405-702-4100.
Thank you for your cooperation in this matter. If I may be of further service, please contact me
at (405) 702- 4200.
Sincerely,
David S. Schutz, P.E.
New Source Permit Section
AIR QUALITY DIVISION
Enclosure
PART 70 PERMIT
AIR QUALITY DIVISION
STATE OF OKLAHOMA
DEPARTMENT OF ENVIRONMENTAL QUALITY
707 N. ROBINSON, SUITE 4100
P.O. BOX 1677
OKLAHOMA CITY, OKLAHOMA 73101-1677
Permit No. 2017-1011-TVR
Targa Pipeline Mid-Continent LLC,
having complied with the requirements of the law, is hereby granted permission to operate
the Tupelo, Coalgate, and Stonewall Gas Plants, Section 6, T1S, R10E, Coal County,
Oklahoma subject to the Standard Conditions dated June 21, 2016 and Specific Conditions,
both attached.
This permit shall expire five (5) years from the issuance date below, except as authorized
under Section B of the Standard Conditions.
_____________________________ ____ _________________________________
Division Director Date
Air Quality Division
DEQ Form #100-890 Revised 10/20/06
MAJOR SOURCE AIR QUALITY PERMIT
STANDARD CONDITIONS
(June 21, 2016)
SECTION I. DUTY TO COMPLY
A. This is a permit to operate / construct this specific facility in accordance with the federal
Clean Air Act (42 U.S.C. 7401, et al.) and under the authority of the Oklahoma Clean Air Act
and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]
B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma
Department of Environmental Quality (DEQ). The permit does not relieve the holder of the
obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or
ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]
C. The permittee shall comply with all conditions of this permit. Any permit noncompliance
shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement
action, permit termination, revocation and reissuance, or modification, or for denial of a permit
renewal application. All terms and conditions are enforceable by the DEQ, by the
Environmental Protection Agency (EPA), and by citizens under section 304 of the Federal Clean
Air Act (excluding state-only requirements). This permit is valid for operations only at the
specific location listed.
[40 C.F.R. §70.6(b), OAC 252:100-8-1.3 and OAC 252:100-8-6(a)(7)(A) and (b)(1)]
D. It shall not be a defense for a permittee in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance with the
conditions of the permit. However, nothing in this paragraph shall be construed as precluding
consideration of a need to halt or reduce activity as a mitigating factor in assessing penalties for
noncompliance if the health, safety, or environmental impacts of halting or reducing operations
would be more serious than the impacts of continuing operations. [OAC 252:100-8-6(a)(7)(B)]
SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS
A. Any exceedance resulting from an emergency and/or posing an imminent and substantial
danger to public health, safety, or the environment shall be reported in accordance with Section
XIV (Emergencies). [OAC 252:100-8-6(a)(3)(C)(iii)(I) & (II)]
B. Deviations that result in emissions exceeding those allowed in this permit shall be reported
consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements.
[OAC 252:100-8-6(a)(3)(C)(iv)]
C. Every written report submitted under this section shall be certified as required by Section III
(Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.
[OAC 252:100-8-6(a)(3)(C)(iv)]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 2
SECTION III. MONITORING, TESTING, RECORDKEEPING & REPORTING
A. The permittee shall keep records as specified in this permit. These records, including
monitoring data and necessary support information, shall be retained on-site or at a nearby field
office for a period of at least five years from the date of the monitoring sample, measurement,
report, or application, and shall be made available for inspection by regulatory personnel upon
request. Support information includes all original strip-chart recordings for continuous
monitoring instrumentation, and copies of all reports required by this permit. Where appropriate,
the permit may specify that records may be maintained in computerized form.
[OAC 252:100-8-6 (a)(3)(B)(ii), OAC 252:100-8-6(c)(1), and OAC 252:100-8-6(c)(2)(B)]
B. Records of required monitoring shall include:
(1) the date, place and time of sampling or measurement;
(2) the date or dates analyses were performed;
(3) the company or entity which performed the analyses;
(4) the analytical techniques or methods used;
(5) the results of such analyses; and
(6) the operating conditions existing at the time of sampling or measurement.
[OAC 252:100-8-6(a)(3)(B)(i)]
C. No later than 30 days after each six (6) month period, after the date of the issuance of the
original Part 70 operating permit or alternative date as specifically identified in a subsequent Part
70 operating permit, the permittee shall submit to AQD a report of the results of any required
monitoring. All instances of deviations from permit requirements since the previous report shall
be clearly identified in the report. Submission of these periodic reports will satisfy any reporting
requirement of Paragraph E below that is duplicative of the periodic reports, if so noted on the
submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)]
D. If any testing shows emissions in excess of limitations specified in this permit, the owner or
operator shall comply with the provisions of Section II (Reporting Of Deviations From Permit
Terms) of these standard conditions. [OAC 252:100-8-6(a)(3)(C)(iii)]
E. In addition to any monitoring, recordkeeping or reporting requirement specified in this
permit, monitoring and reporting may be required under the provisions of OAC 252:100-43,
Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean
Air Act or Oklahoma Clean Air Act. [OAC 252:100-43]
F. Any Annual Certification of Compliance, Semi Annual Monitoring and Deviation Report,
Excess Emission Report, and Annual Emission Inventory submitted in accordance with this
permit shall be certified by a responsible official. This certification shall be signed by a
responsible official, and shall contain the following language: “I certify, based on information
and belief formed after reasonable inquiry, the statements and information in the document are
true, accurate, and complete.”
[OAC 252:100-8-5(f), OAC 252:100-8-6(a)(3)(C)(iv), OAC 252:100-8-6(c)(1), OAC
252:100-9-7(e), and OAC 252:100-5-2.1(f)]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 3
G. Any owner or operator subject to the provisions of New Source Performance Standards
(“NSPS”) under 40 CFR Part 60 or National Emission Standards for Hazardous Air Pollutants
(“NESHAPs”) under 40 CFR Parts 61 and 63 shall maintain a file of all measurements and other
information required by the applicable general provisions and subpart(s). These records shall be
maintained in a permanent file suitable for inspection, shall be retained for a period of at least
five years as required by Paragraph A of this Section, and shall include records of the occurrence
and duration of any start-up, shutdown, or malfunction in the operation of an affected facility,
any malfunction of the air pollution control equipment; and any periods during which a
continuous monitoring system or monitoring device is inoperative.
[40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q]
H. The permittee of a facility that is operating subject to a schedule of compliance shall submit
to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for
achieving the activities, milestones or compliance required in the schedule of compliance and the
dates when such activities, milestones or compliance was achieved. The progress reports shall
also contain an explanation of why any dates in the schedule of compliance were not or will not
be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)]
I. All testing must be conducted under the direction of qualified personnel by methods
approved by the Division Director. All tests shall be made and the results calculated in
accordance with standard test procedures. The use of alternative test procedures must be
approved by EPA. When a portable analyzer is used to measure emissions it shall be setup,
calibrated, and operated in accordance with the manufacturer’s instructions and in accordance
with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document
or an equivalent method approved by Air Quality.
[OAC 252:100-8-6(a)(3)(A)(iv), and OAC 252:100-43]
J. The reporting of total particulate matter emissions as required in Part 7 of OAC 252:100-8
(Permits for Part 70 Sources), OAC 252:100-19 (Control of Emission of Particulate Matter), and
OAC 252:100-5 (Emission Inventory), shall be conducted in accordance with applicable testing
or calculation procedures, modified to include back-half condensables, for the concentration of
particulate matter less than 10 microns in diameter (PM10). NSPS may allow reporting of only
particulate matter emissions caught in the filter (obtained using Reference Method 5).
K. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required
by 40 C.F.R. Part 60, 61, and 63, for all equipment constructed or operated under this permit
subject to such standards. [OAC 252:100-8-6(c)(1) and OAC 252:100, Appendix Q]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 4
SECTION IV. COMPLIANCE CERTIFICATIONS
A. No later than 30 days after each anniversary date of the issuance of the original Part 70
operating permit or alternative date as specifically identified in a subsequent Part 70 operating
permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a
certification of compliance with the terms and conditions of this permit and of any other
applicable requirements which have become effective since the issuance of this permit.
[OAC 252:100-8-6(c)(5)(A), and (D)]
B. The compliance certification shall describe the operating permit term or condition that is the
basis of the certification; the current compliance status; whether compliance was continuous or
intermittent; the methods used for determining compliance, currently and over the reporting
period. The compliance certification shall also include such other facts as the permitting
authority may require to determine the compliance status of the source.
[OAC 252:100-8-6(c)(5)(C)(i)-(v)]
C. The compliance certification shall contain a certification by a responsible official as to the
results of the required monitoring. This certification shall be signed by a responsible official,
and shall contain the following language: “I certify, based on information and belief formed
after reasonable inquiry, the statements and information in the document are true, accurate, and
complete.” [OAC 252:100-8-5(f) and OAC 252:100-8-6(c)(1)]
D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions
units or stationary sources that are not in compliance with all applicable requirements. This
schedule shall include a schedule of remedial measures, including an enforceable sequence of
actions with milestones, leading to compliance with any applicable requirements for which the
emissions unit or stationary source is in noncompliance. This compliance schedule shall
resemble and be at least as stringent as that contained in any judicial consent decree or
administrative order to which the emissions unit or stationary source is subject. Any such
schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the
applicable requirements on which it is based, except that a compliance plan shall not be required
for any noncompliance condition which is corrected within 24 hours of discovery.
[OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)]
SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE
PERMIT TERM
The permittee shall comply with any additional requirements that become effective during the
permit term and that are applicable to the facility. Compliance with all new requirements shall
be certified in the next annual certification. [OAC 252:100-8-6(c)(6)]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 5
SECTION VI. PERMIT SHIELD
A. Compliance with the terms and conditions of this permit (including terms and conditions
established for alternate operating scenarios, emissions trading, and emissions averaging, but
excluding terms and conditions for which the permit shield is expressly prohibited under OAC
252:100-8) shall be deemed compliance with the applicable requirements identified and included
in this permit. [OAC 252:100-8-6(d)(1)]
B. Those requirements that are applicable are listed in the Standard Conditions and the Specific
Conditions of this permit. Those requirements that the applicant requested be determined as not
applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6(d)(2)]
SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT
The permittee shall file with the AQD an annual emission inventory and shall pay annual fees
based on emissions inventories. The methods used to calculate emissions for inventory purposes
shall be based on the best available information accepted by AQD.
[OAC 252:100-5-2.1, OAC 252:100-5-2.2, and OAC 252:100-8-6(a)(8)]
SECTION VIII. TERM OF PERMIT
A. Unless specified otherwise, the term of an operating permit shall be five years from the date
of issuance. [OAC 252:100-8-6(a)(2)(A)]
B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely
and complete renewal application has been submitted at least 180 days before the date of
expiration. [OAC 252:100-8-7.1(d)(1)]
C. A duly issued construction permit or authorization to construct or modify will terminate and
become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction
is not commenced within 18 months after the date the permit or authorization was issued, or if
work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)]
D. The recipient of a construction permit shall apply for a permit to operate (or modified
operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)]
SECTION IX. SEVERABILITY
The provisions of this permit are severable and if any provision of this permit, or the application
of any provision of this permit to any circumstance, is held invalid, the application of such
provision to other circumstances, and the remainder of this permit, shall not be affected thereby.
[OAC 252:100-8-6 (a)(6)]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 6
SECTION X. PROPERTY RIGHTS
A. This permit does not convey any property rights of any sort, or any exclusive privilege.
[OAC 252:100-8-6(a)(7)(D)]
B. This permit shall not be considered in any manner affecting the title of the premises upon
which the equipment is located and does not release the permittee from any liability for damage
to persons or property caused by or resulting from the maintenance or operation of the equipment
for which the permit is issued. [OAC 252:100-8-6(c)(6)]
SECTION XI. DUTY TO PROVIDE INFORMATION
A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty
(60) days of the request unless the DEQ specifies another time period, any information that the
DEQ may request to determine whether cause exists for modifying, reopening, revoking,
reissuing, terminating the permit or to determine compliance with the permit. Upon request, the
permittee shall also furnish to the DEQ copies of records required to be kept by the permit.
[OAC 252:100-8-6(a)(7)(E)]
B. The permittee may make a claim of confidentiality for any information or records submitted
pursuant to 27A O.S. § 2-5-105(18). Confidential information shall be clearly labeled as such
and shall be separable from the main body of the document such as in an attachment.
[OAC 252:100-8-6(a)(7)(E)]
C. Notification to the AQD of the sale or transfer of ownership of this facility is required and
shall be made in writing within thirty (30) days after such sale or transfer.
[Oklahoma Clean Air Act, 27A O.S. § 2-5-112(G)]
SECTION XII. REOPENING, MODIFICATION & REVOCATION
A. The permit may be modified, revoked, reopened and reissued, or terminated for cause.
Except as provided for minor permit modifications, the filing of a request by the permittee for a
permit modification, revocation and reissuance, termination, notification of planned changes, or
anticipated noncompliance does not stay any permit condition.
[OAC 252:100-8-6(a)(7)(C) and OAC 252:100-8-7.2(b)]
B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the
following circumstances: [OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)]
(1) Additional requirements under the Clean Air Act become applicable to a major source
category three or more years prior to the expiration date of this permit. No such
reopening is required if the effective date of the requirement is later than the expiration
date of this permit.
(2) The DEQ or the EPA determines that this permit contains a material mistake or that the
permit must be revised or revoked to assure compliance with the applicable requirements.
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 7
(3) The DEQ or the EPA determines that inaccurate information was used in establishing the
emission standards, limitations, or other conditions of this permit. The DEQ may revoke
and not reissue this permit if it determines that the permittee has submitted false or
misleading information to the DEQ.
(4) DEQ determines that the permit should be amended under the discretionary reopening
provisions of OAC 252:100-8-7.3(b).
C. The permit may be reopened for cause by EPA, pursuant to the provisions of OAC 100-8-
7.3(d). [OAC 100-8-7.3(d)]
D. The permittee shall notify AQD before making changes other than those described in Section
XVIII (Operational Flexibility), those qualifying for administrative permit amendments, or those
defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). The
notification should include any changes which may alter the status of a “grandfathered source,”
as defined under AQD rules. Such changes may require a permit modification.
[OAC 252:100-8-7.2(b) and OAC 252:100-5-1.1]
E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that
are not specifically approved by this permit are prohibited. [OAC 252:100-8-6(c)(6)]
SECTION XIII. INSPECTION & ENTRY
A. Upon presentation of credentials and other documents as may be required by law, the
permittee shall allow authorized regulatory officials to perform the following (subject to the
permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(17)
for confidential information submitted to or obtained by the DEQ under this section):
(1) enter upon the permittee's premises during reasonable/normal working hours where a
source is located or emissions-related activity is conducted, or where records must be
kept under the conditions of the permit;
(2) have access to and copy, at reasonable times, any records that must be kept under the
conditions of the permit;
(3) inspect, at reasonable times and using reasonable safety practices, any facilities,
equipment (including monitoring and air pollution control equipment), practices, or
operations regulated or required under the permit; and
(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times
substances or parameters for the purpose of assuring compliance with the permit.
[OAC 252:100-8-6(c)(2)]
SECTION XIV. EMERGENCIES
A. Any exceedance resulting from an emergency shall be reported to AQD promptly but no later
than 4:30 p.m. on the next working day after the permittee first becomes aware of the
exceedance. This notice shall contain a description of the emergency, the probable cause of the
exceedance, any steps taken to mitigate emissions, and corrective actions taken.
[OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 8
B. Any exceedance that poses an imminent and substantial danger to public health, safety, or the
environment shall be reported to AQD as soon as is practicable; but under no circumstance shall
notification be more than 24 hours after the exceedance. [OAC 252:100-8-6(a)(3)(C)(iii)(II)]
C. An "emergency" means any situation arising from sudden and reasonably unforeseeable
events beyond the control of the source, including acts of God, which situation requires
immediate corrective action to restore normal operation, and that causes the source to exceed a
technology-based emission limitation under this permit, due to unavoidable increases in
emissions attributable to the emergency. An emergency shall not include noncompliance to the
extent caused by improperly designed equipment, lack of preventive maintenance, careless or
improper operation, or operator error. [OAC 252:100-8-2]
D. The affirmative defense of emergency shall be demonstrated through properly signed,
contemporaneous operating logs or other relevant evidence that: [OAC 252:100-8-6 (e)(2)]
(1) an emergency occurred and the permittee can identify the cause or causes of the
emergency;
(2) the permitted facility was at the time being properly operated;
(3) during the period of the emergency the permittee took all reasonable steps to minimize
levels of emissions that exceeded the emission standards or other requirements in this
permit.
E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an
emergency shall have the burden of proof. [OAC 252:100-8-6(e)(3)]
F. Every written report or document submitted under this section shall be certified as required
by Section III (Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.
[OAC 252:100-8-6(a)(3)(C)(iv)]
SECTION XV. RISK MANAGEMENT PLAN
The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop
and register with the appropriate agency a risk management plan by June 20, 1999, or the
applicable effective date. [OAC 252:100-8-6(a)(4)]
SECTION XVI. INSIGNIFICANT ACTIVITIES
Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to
operate individual emissions units that are either on the list in Appendix I to OAC Title 252,
Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below.
Any activity to which a State or Federal applicable requirement applies is not insignificant even
if it meets the criteria below or is included on the insignificant activities list.
(1) 5 tons per year of any one criteria pollutant.
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 9
(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an
aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year
for single HAP that the EPA may establish by rule.
[OAC 252:100-8-2 and OAC 252:100, Appendix I]
SECTION XVII. TRIVIAL ACTIVITIES
Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to
operate any individual or combination of air emissions units that are considered inconsequential
and are on the list in Appendix J. Any activity to which a State or Federal applicable
requirement applies is not trivial even if included on the trivial activities list.
[OAC 252:100-8-2 and OAC 252:100, Appendix J]
SECTION XVIII. OPERATIONAL FLEXIBILITY
A. A facility may implement any operating scenario allowed for in its Part 70 permit without the
need for any permit revision or any notification to the DEQ (unless specified otherwise in the
permit). When an operating scenario is changed, the permittee shall record in a log at the facility
the scenario under which it is operating. [OAC 252:100-8-6(a)(10) and (f)(1)]
B. The permittee may make changes within the facility that:
(1) result in no net emissions increases,
(2) are not modifications under any provision of Title I of the federal Clean Air Act, and
(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit
to be exceeded;
provided that the facility provides the EPA and the DEQ with written notification as required
below in advance of the proposed changes, which shall be a minimum of seven (7) days, or
twenty four (24) hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the
DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such
change, the written notification required above shall include a brief description of the change
within the permitted facility, the date on which the change will occur, any change in emissions,
and any permit term or condition that is no longer applicable as a result of the change. The
permit shield provided by this permit does not apply to any change made pursuant to this
paragraph. [OAC 252:100-8-6(f)(2)]
SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS
A. The following applicable requirements and state-only requirements apply to the facility
unless elsewhere covered by a more restrictive requirement:
(1) Open burning of refuse and other combustible material is prohibited except as authorized
in the specific examples and under the conditions listed in the Open Burning Subchapter.
[OAC 252:100-13]
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 10
(2) No particulate emissions from any fuel-burning equipment with a rated heat input of 10
MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19]
(3) For all emissions units not subject to an opacity limit promulgated under 40 C.F.R., Part
60, NSPS, no discharge of greater than 20% opacity is allowed except for:
[OAC 252:100-25]
(a) Short-term occurrences which consist of not more than one six-minute period in any
consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours.
In no case shall the average of any six-minute period exceed 60% opacity;
(b) Smoke resulting from fires covered by the exceptions outlined in OAC 252:100-13-7;
(c) An emission, where the presence of uncombined water is the only reason for failure
to meet the requirements of OAC 252:100-25-3(a); or
(d) Smoke generated due to a malfunction in a facility, when the source of the fuel
producing the smoke is not under the direct and immediate control of the facility and
the immediate constriction of the fuel flow at the facility would produce a hazard to
life and/or property.
(4) No visible fugitive dust emissions shall be discharged beyond the property line on which
the emissions originate in such a manner as to damage or to interfere with the use of
adjacent properties, or cause air quality standards to be exceeded, or interfere with the
maintenance of air quality standards. [OAC 252:100-29]
(5) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2
lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur
dioxide. [OAC 252:100-31]
(6) Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and
with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia
or greater under actual conditions shall be equipped with a permanent submerged fill pipe
or with a vapor-recovery system. [OAC 252:100-37-15(b)]
(7) All fuel-burning equipment shall at all times be properly operated and maintained in a
manner that will minimize emissions of VOCs. [OAC 252:100-37-36]
SECTION XX. STRATOSPHERIC OZONE PROTECTION
A. The permittee shall comply with the following standards for production and consumption of
ozone-depleting substances: [40 CFR 82, Subpart A]
(1) Persons producing, importing, or placing an order for production or importation of certain
class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the
requirements of §82.4;
(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain
class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping
requirements at §82.13; and
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 11
(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons,
HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane
(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include
HCFCs.
B. If the permittee performs a service on motor (fleet) vehicles when this service involves an
ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air
conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term
“motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the
vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the
air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger
buses using HCFC-22 refrigerant. [40 CFR 82, Subpart B]
C. The permittee shall comply with the following standards for recycling and emissions
reduction except as provided for MVACs in Subpart B: [40 CFR 82, Subpart F]
(1) Persons opening appliances for maintenance, service, repair, or disposal must comply
with the required practices pursuant to § 82.156;
(2) Equipment used during the maintenance, service, repair, or disposal of appliances must
comply with the standards for recycling and recovery equipment pursuant to § 82.158;
(3) Persons performing maintenance, service, repair, or disposal of appliances must be
certified by an approved technician certification program pursuant to § 82.161;
(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply
with record-keeping requirements pursuant to § 82.166;
(5) Persons owning commercial or industrial process refrigeration equipment must comply
with leak repair requirements pursuant to § 82.158; and
(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant
must keep records of refrigerant purchased and added to such appliances pursuant to §
82.166.
SECTION XXI. TITLE V APPROVAL LANGUAGE
A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is
not inconsistent with Federal requirements, to provide for incorporation of requirements
established through construction permitting into the Source’s Title V permit without causing
redundant review. Requirements from construction permits may be incorporated into the Title V
permit through the administrative amendment process set forth in OAC 252:100-8-7.2(a) only if
the following procedures are followed:
MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 12
(1) The construction permit goes out for a 30-day public notice and comment using the
procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice to
the public that this permit is subject to EPA review, EPA objection, and petition to
EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit
will be incorporated into the Title V permit through the administrative amendment
process; that the public will not receive another opportunity to provide comments when
the requirements are incorporated into the Title V permit; and that EPA review, EPA
objection, and petitions to EPA will not be available to the public when requirements
from the construction permit are incorporated into the Title V permit.
(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR §
70.8(a)(1).
(3) A copy of the draft construction permit is sent to any affected State, as provided by 40
C.F.R. § 70.8(b).
(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period
as provided by 40 C.F.R.§ 70.8(a) and (c).
(5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day
comment period of any EPA objection to the construction permit. The DEQ shall not
issue the permit until EPA’s objections are resolved to the satisfaction of EPA.
(6) The DEQ complies with 40 C.F.R. § 70.8(d).
(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8(a).
(8) The DEQ shall not issue the proposed construction permit until any affected State and
EPA have had an opportunity to review the proposed permit, as provided by these
permit conditions.
(9) Any requirements of the construction permit may be reopened for cause after
incorporation into the Title V permit by the administrative amendment process, by
DEQ as provided in OAC 252:100-8-7.3(a), (b), and (c), and by EPA as provided in 40
C.F.R. § 70.7(f) and (g).
(10) The DEQ shall not issue the administrative permit amendment if performance tests fail
to demonstrate that the source is operating in substantial compliance with all permit
requirements.
B. To the extent that these conditions are not followed, the Title V permit must go through the
Title V review process.
SECTION XXII. CREDIBLE EVIDENCE
For the purpose of submitting compliance certifications or establishing whether or not a person
has violated or is in violation of any provision of the Oklahoma implementation plan, nothing
shall preclude the use, including the exclusive use, of any credible evidence or information,
relevant to whether a source would have been in compliance with applicable requirements if the
appropriate performance or compliance test or procedure had been performed.
[OAC 252:100-43-6]
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